Polymer Injection in a Deep Offshore Field - Angola, Dalia/Camelia Field Case
- Dennis Denney (JPT Senior Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 2011
- Document Type
- Journal Paper
- 89 - 91
- 2011. Society of Petroleum Engineers
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- 156 since 2007
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This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 135735, "First Polymer Injection in a Deep Offshore Field - Angola: Recent Advances on Dalia/ Camelia Field Case," by Danielle Morel, SPE, and Michel Vert, Total E&P; Stephane Jouenne, SPE, Total Petrochemicals; and Renaud Gauchet and Yann Bouger, Total E&P Angola, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.
Key challenges of the polymer-injection project in the Dalia field, offshore Angola, were to start polymer injection:
- Very early in the field development
- With much wider well spacing than in other projects
- Under high-salinity conditions (>25g/L)
- With specific logistics of a remote deep offshore area
The Dalia field is 130 km offshore Angola, with an estimated 1 billion bbl of recoverable oil. Water depth varies between 1200 and 1400 m, with reservoirs 800 to 1000 m below the seabed. Very-high-quality 3D-seismic data enabled mapping of the main reservoir structure, including sands and clay areas only 6 to 10 m thick. The channel complexes can be as thick as 100 m but are divided into heterogeneous sections with alternating layers of oil sands and clays. Permeability ranges from a few hundred millidarcies to several darcies, with an average permeability greater than 1 darcy. The reservoir temperature ranges from 45 to 56°C, and reservoir pressure is 215 to 235 bar. The 19 to 38°API oil is slightly undersaturated, with viscosity ranging from 1 to 11 cp at reservoir conditions. Water viscosity is approximately 0.5 cp at reservoir conditions.
The field produces by energy from water injection, using a floating production, storage, and offloading (FPSO) vessel with 31 deviated or horizontal subsea injector wells and four injection flowlines. Generally, a single flowline is used to inject into several reservoirs and several systems. Maximum water injection is 405,000 BWPD. Production is achieved through four production lines and 37 producers. First oil was on 13 December 2006. The 240,000-BOPD plateau rate was reached after a few months and has been maintained since.
Seawater is desulfated to prevent risk of barium sulfate deposit, and has been injected from the start. Produced water will be reinjected after water breakthrough. By June 2010, 25 producer wells were connected and water breakthrough had occurred in several wells, with water cut ranging from a few percent to more than 40%. The current water-injection salinity is approximately 50 g/L.
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