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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 The paper has not been peer reviewed.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 1.012×10 std m, 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/cm, 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 9.79×10 m/d. Oil production averaged 4.48×10 m/d, with water cut of 54% in April 2010. The cumulative oil production surpassed 3.18×10 m 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.
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Field > Macae Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Field > Lago Feia Formation (0.99)
- South America > Brazil > Campos Basin > Campos Field (0.97)
- (2 more...)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145005, ’A Case Study: A Successful Steamflooding Project To Enhance Oil Recovery of a Low-Permeability Light-Oil Waterflood Reservoir,’ by Wu Shuhong, SPE, PetroChina; Han Min, Greatwall Drilling Company; Ma Desheng and Wu Yongbin, PetroChina; Qian Yu and Yao Chunli, Daqing Oil Company; and Shen Dehuang, SPE, PetroChina, prepared for the 2011 SPE Enhanced Oil Recovery Conference, Kuala Lumpur, 19-21 July 2011. The paper has not been peer reviewed. Steamflooding can improve upon performance of a waterflood light-oil reservoir and enhance its oil recovery. In the Cy reservoir of the Daqing oil field, a steamflooding project is enhancing oil recovery after waterflooding. The mechanisms, strategies, barriers, and difficulties of reaching high recovery are discussed for steamflooding in a waterflooded light-oil low-permeability reservoir. A detailed reservoir-engineering study focused on the development method, the injection and production system, and the physical and numerical simulation. Introduction Steamflooding in heavy-oil sands is well documented as a mature technology, and while steam has been injected into light-oil low-permeability sands for almost as long, the mechanisms and effectiveness of this process are much less understood because of flow complexities in these sands and complexities of high-pressure steam injection. The full-length paper details the examination of thermal recovery in such a reservoir by use of physical and numerical simulations. Wettability alteration, interfacial tension, and threshold-pressure-gradient decline contribute to higher oil displacement and sweep efficiency. Vaporization, viscosity reduction, thermal expansion, and relative permeability variation account for more than three-fourths of the incremental recovery in steamflooding. The Cy reservoir is a low-permeability reservoir with a high wax content and oil viscosity ranging from 16 to 95 mPa·s. It underwent 10 years of waterflooding with only 10% of the original oil in place (OOIP) recovered from the reservoir. Challenges faced in this complex project were related to the heterogeneous nature of the reservoir, limited sand continuity, unfavorable mobility for the ongoing waterflooding, associated high thresh-old-pressure gradient, and poor injection response. In 2007, steamflooding was initiated to improve the performance and enhance oil recovery. The steamflooding project has shown promising results. The response to steam injection was quick and significant. Injectivity has doubled and productivity has almost tripled. Geological Characteristics The width of this massive sandstone is 1000 to 1500 m. The thickness is 2 to 4 m. It has low-permeability sandstone units interspersed with shales. The permeability range is 1 to 20 md, and porosity is 12 to 18%. Both the initial fractures and the hydraulic fractures develop in the west/east direction. Block C601 is 770 to 880 m deep with a reservoir temperature of 55°C and reservoir pressure of 8.4 MPa. The crude oil has high wax content and a high wax-precipitation point of 15.9 to 25.9% and 49 to 52°C, respectively. At reservoir temperature, the oil viscosity is 16 to 95 mPa·s, averaging 40 mPa·s.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.89)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.63)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.45)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)