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Marlim is the name of a giant Brazilian oil field located in the north-eastern part of the Campos Basin, about 110 km offshore Rio de Janeiro, in water depths ranging from 650 to 1,050 m. Reservoir depths are 2500 to 2750 m, with temperatures between 65 and 72°C. Marlim means marlin, in Portuguese.

Marlim was originally discovered by well in February 1985. The 75 m column was predominantly unconsolidated sandstone, with a permeability as high as two darcies. The discovery also showed high-gravity oil (17-21 degree API). At the time of discovery, the Marlim reservoir had an oil-in-place volume of about 9 billion barrels, expectated 1.7 billion barrels of oil in total reserves, original pressure of  4,082 psi, and the saturation pressure was 3,769 psi.

Geology
The Marlim field consists of a single Oligocene producing horizon of sandstone turbidites, with an area of 152 km2. Reflection seismology in 1972 disclosed a faulted anticline and seismic amplitude bright spot, which was drilled by wildcat 1-RJS-219A in 1985 and discovered oil. The stratigraphy of the Campos Basin starts with the Lower Cretaceous Lago Feia Formation a source rock, followed by the Albian Macae Formation consisting of shallow water carbonates overlain by late Albian shales, marls, calcilutites, and turbidite sandstones. From this formation through most of the Cenozoic, the Campos Formation was deposited, consisting of deep water turbiditic sandstones and shales, the main producers in the Albacora and Marlim fields. Finally, the basin was filled by the Ubatuba Formation, consisting of slope and shelf deposits. The Oligocene turbidite reservoir forms part of the Middle Eocene to Recent marine regressive megasequence from the eastern Brazilian margin, it is formed by a group of depositional systems (displaying a progradational pattern) which include strand-plain, siliciclastic shelf, fluvial-deltaic, fan delta, carbonate platform, slope, and deep-basin systems (Fig. 2). A regional northwest–southeast transfer faults system contributed into the formation of the turbidite sedimentation by creating a new passageway for the turbidite sedimentation and allowing redistribution of several deepwater reservoirs in the Campos Basin (Cobbold et al., 2001). These turbidite systems are responsible for forming most of the petroleum reservoirs in the Campos Basin (Bruhn et al., 2003). The reservoir facies have an amalgamated inverse grading beds of unstratified, with medium to very fine-grained sandstones. All of the sandstone facies are poorly-consolidated, poorly-sorted, and have average low silt (<10%), and clay (<2%) contents).

Marlim's sand-rich reservoirs are thick and laterally continuous (blanket geometry), with a geometry of 5-60 meter thick, 2-8 km-wide, and 5-12 km long turbidite lobes. Figure 2 shows accumulated in intra-slope, wide depressions developed due to the eastward tilting of the basin, and the causing a downslope gliding of underlying, Aptian evaporites. There are 125 m-thick successions amalgamation in several lobes with net-to-gross ratio typically ranging 80-100%. Most of the reservoirs displays a blocky pattern in gamma ray logs due to their uniform and low clay matrix. The density logs show porostiy increasing-upward, which are caused by sand-rich successions that become finergrained and better-sorted upward. Reservoir porosities and permeabilities are relatively homogeneous, typically averaging 27-30%, and 1,000-2,000 md, respectively.

Sections of Marlim field have discontinuous geometry due to partial erosion by younger, low to high sinuosity, mud-filled channels. Some of the heterogeneities of internal reservoir compromise of layers of calcite-rich, and bioturbated shale-rich horizons and mars (< 3 m-thick), they benthic foraminifera characteristic of mid to lower bathyal settings. However, internal heterogeneities do not act across the field because of widespread barriers for pressure transmission, according to RFT data from the Marlim Field wells.

Other characteristics of the Marlim fields include water saturation of 14%, porosity of 25%, initial gas oil ratio of 80, and a oil-water contact at 2740m. These characteristics have been derived mainly from seismic, especially amplitude anomaly, well log analysis, and drill-stem tests.[4] excellent permeability characteristics. The main problem can be sand production, which requires gravel-packing that can reduce, significantly, the productivity of the wells. Petrophysical analysis indicated original water saturation of 15% coming from a small aquifers under underlying the oil

Campos Basin Stratigraphy
Campos Basin sedimentary section is divided into three megasequences according to the tectonic development stages: rift, transitional, and drift (Figure 2). The Barremian lacustrine sediments of Lagoa Feia Formation are considered to be the source rock in the Campos Basin, including Marlim. They are above the Hauterivian Cabiúnas basalts (120–130 Ma); these basalts forms the basement of the Campos Basin. The Aptian sequence consist of conglomerates base, carbonates, and evaporitic rocks deposited on top during a period of tectonic quiescence. This transitional stage corresponds to the beginning of the drift phase in which the sediments are related to the first seawater inflows through the Walvis Ridge.

The drift stage begins with a marine megasequence that is distinguished by the calcilutites of the Macaé Formation and Albian/Cenomanian shallow-water calcarenites. Between the Upper Cretaceous and the Paleogene deepwater clastic section (Carapebus Formation) there is shale, marls, and sandstone turbidites, which have been deposited during a period of tectonic quiescence and of continued subsidence. The remaining Neogene section are characterize by the progradational siliciclastic sequences. The deep water of Campos Basin the deposition has been strongly conditioned by salt tectonics (Mohriak et al., 1996).

Trap
Marlim combines structural and stratigraphic trapping elements. The stratigraphic trapping consist of a pinch out against marls and shales to the north, west, and south. The pinch out is formed by the low-stand systems tract of a third-order sequence, originated by sea level fall around 25 MMy. .The structural trap is a normal listric fault caused by the movement within salt layers. located eastern, northeastern, and northwestern pool boundaries, this fault also acts as a route for oil migration from the presalt source rocks to the turbidite reservoir. The turbidite lobes supply an intraslope, an extensive depression generated by down-slope gliding of underlying Aptian evaporates.[3]

History
The oil field was discovered by an exploratory well that drilled at water depth of 850 m, it uncovered an Oligocene / Miocene reservoir with a thickness of 70 m and an oil of 20 API. Production started in 1991, with an experimental system encompassing of 7 wells attached to a semi-submersible unit moored in a water depth of 600 m. The seven wells were all perforated at the top sand of the reservoir. The production pilot gathered valuable information which contributed to the proceeding phases of the field development, such as showing that all sands depleted at similar rate, therefore revealing good vertical communication in the reservoir. Water injection began in September 1994. Marlim field exploitation plan revolves around the use of water injection as a strategic source of reservoir energy replenishing. Oil and water mass balance is analysed by the constantly monitoring the well drilling sequence. Relative permeabilities have shown to be favorable to water injection. To guarantee the presence of good hydraulic connectivity between the producers and the corresponding injectors seismic resolution utilized or the production data analysis must be of adequate quality. The field is 100% operated by Petrobras, who achieved a production peak of 610,000 bbl/day in April 2002. In 2008 a total of 205 wells were drilled in the Marlim field, of which 81 wells at that time were operating as producers and 44 as injectors. Many deep water well technologies have been employed to develop through the Marlim Complex such as 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.