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Marlim Field: Mature-Field Optimization

2012; Society of Petroleum Engineers; Volume: 64; Issue: 01 Linguagem: Inglês

10.2118/0112-0082-jpt

1944-978X

Dennis Denney,

Hydraulic Fracturing and Reservoir Analysis

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139376, ’Marlim Field: An Optimization Study on a Mature Field,’ by Dirceu Bampi, Petrobras, and Odair Jose Costa, Halliburton, prepared for the 2010 SPE Latin American & Caribbean Petroleum Engineering Conference, Lima, Peru, 1-3 December. The paper has not been peer reviewed. Giant fields provide a significant portion of the total hydrocarbon production in Brazil. Most of these fields are in advanced exploitation stages. A drainage-optimization study was performed on the Marlim field, a giant and mature field in the Brazilian Campos basin. Reservoir-flow simulations were used to optimize the methodology and increase the recoverable-oil volume by accelerating the oil production. As a result, new-well proposals became more economically attractive. Introduction The Marlim field, discovered in 1985, is in the northeastern part of the Campos basin in water depths between 600 and 1200 m. Reservoir depths are 2500 to 2750 m, with temperatures between 65 and 72°C. Marlim is part of a large complex of reservoirs including the Marlim Sul and Marlim Leste fields. The original oil in place is 1.012×109 std m3, and the maximum permeable thickness is 125 m. The reservoir is unconsolidated sand-stone with an average net-/gross-thick-ness ratio of 86%, average porosity of 30%, and permeability of 1 to 10 dar-cies. The petrophysical analysis indicated original water saturation of 15%, saturation pressure of 265 kgf/cm2, and residual-oil saturation of 23%. The oil at reservoir conditions has a viscosity of 4–8 cp and gravity of 18–25°API. The reservoir is divided into five stratigraphic zones. Every zone is in hydraulic communication, although, in some areas, the communication is somewhat constrained. The reservoir has small aquifers underlying the oil, and solution-gas drive is the main production mechanism. The reservoir is undergoing a secondary-recovery process by use of seawater injection. Production startup occurred in March 1991, and water injection began in September 1994. Peak production occurred in April 2002 with 9.79×104 m3/d. Oil production averaged 4.48×104 m3/d, with water cut of 54% in April 2010. The cumulative oil production surpassed 3.18×108 m3 in April 2010, representing 32% recovery. The field contains more than 200 wells, with 125 in operation and a producer/injector ratio of 1.85. The current reservoir-exploitation stage, with oil-production decline and a significant increase in water production, presents serious challenges in maintaining extraction cost at acceptable levels. To accelerate field oil production and increase the recoverable volume, this simulation-optimization study considered drilling 16 new producing wells and attempted to identify targets for future sidetracks from these new wells.