Polymer Injection in Deepwater Field Offshore Angola

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174699, “Dalia/Camelia Polymer Injection in Deep Offshore Field, Angola: Learnings and In-Situ Polymer-Sampling Results,” by D.C. Morel, E. Zaugg, S. Jouenne, J.A. Danquigny, and P.R. Cordelier, Total, prepared for the 2015 SPE Enhanced Oil Recovery Conference, Kuala Lumpur, 11–13 August. The paper has not been peer reviewed. The polymer-injection project in the Dalia field, one of the main fields of Block 17 in deepwater Angola, represents a world first for both surface and subsurface aspects. Thorough, integrated geoscience and architectural studies led to the decision to initiate a polymer-injectivity test on a single well, followed by a continuous injection of polymer on one of the four subsea lines delivering water to the field. The complete paper describes the main results of the pilot phase. Introduction A subsea development scheme with water injection for full pressure maintenance was chosen for the Dalia field together with gas reinjection. Very early in the geoscience studies, oil viscosity was identified as the main limiting factor to water-injection recovery. Polymer injection was positively screened as a potential enhanced-oil-recovery method for the field. Extensive feasibility studies of polymer flooding were initiated in 2003, 3 years before production start-up. A phased approach was chosen to assess and reduce the main uncertainties of the project, consisting of the construction of a powder-polymer solution-preparation skid, a single-well injectivity test, a longer injection period through one of the injection lines (supplying three wells), and the drilling of a sampler/producer well to assess in-situ viscosity, while continuing surface and subsurface studies. Dalia Reservoir The field is developed by water injection, using a floating production, storage, and offloading (FPSO) vessel with 28 deviated or horizontal subsea injector wells and four injection flowlines (plus three gas-reinjection wells active before Angolan liquefied-natural-gas startup). A single flowline generally injects into several reservoirs as well as several systems. Maximum yearly average water injection is 360,000 BWPD. Desulfated seawater has been injected since startup to prevent any barium sulfate deposition, and all the produced water is reinjected. Production is achieved through four production lines and 40 producers. First oil was on 13 December 2006. The 240,000-B/D oil-production plateau was reached after a few months, while, at the time of this writing, 8 years after startup, the field is still producing at a reduced plateau rate of 200,000 BOPD. A schematic of the layout is provided in Fig. 1.