Real-Time Reservoir Management in a High-Cost Deepwater Environment - Greater Plutonio
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 128542, ’Greater Plutonio - Real-Time Reservoir Man age - ment in a High-Cost Deepwater En vironment,’ by Dave Booth, SPE, and Pedro Sebastiao, SPE, BP plc, prepared for the 2010 SPE Intelligent Energy Conference and Exhibition, Utrecht, The Netherlands, 23-25 March. The paper has not been peer reviewed.
Greater Plutonio is a large subsea development with a planned first phase of 43 high-rate subsea wells. A relatively low level of classical field appraisal was performed because of high costs. Innovative subsurface management was required to reduce substantial uncertainty during the development phase. Remote access to real-time data enabled making better decisions faster and reducing the number of field staff.
Introduction
The Greater Plutonio fields (Plutonio, Cobalto, Galio, Cromio, and Paladio) were discovered offshore Angola between 1999 and 2000 and are Upper Oligocene turbidite reservoirs. Changes in fluid and lithology in the semiconsolidated reservoir rocks manifest themselves as distinct changes in seismic response. Water depths are between 1200 and 1400 m, and a relatively dispersed resource base resulted in the most viable development concept being a 100% subsea-well development with multikilometer-scale well spacing produced through a large floating production, storage, and offloading (FPSO) vessel.
The initial development phase of 43 wells, plus up to 25 additional infill and sidetrack wells, was the largest subsea development undertaken by the operator. Of the initial 43 wells, 23 are injection wells, and most are completed across multiple reservoirs with full sand control. At the time of writing this paper, 34 wells had been drilled, and subsurface outcome was largely as expected.
All reservoirs are waterflooded, with approximately one-half the injection wells having downhole flow control (DHFC) to improve injection management. The high-porosity rocks often have permeability exceeding 1 darcy, which, combined with high-gravity oil, provide a favorable mobility ratio and very efficient displacement. Recovery factors in some reservoirs should exceed 50%. The associated gas is injected through two wells in the Plutonio field to provide pressure support. This process will continue for 3 to 4 years after field startup, until gas export is available after commissioning of the Angola liquefied-natural-gas project. All of the production wells have openhole-gravel-pack (OHGP) completions, some with openhole completion lengths of up to 800 m.
Although confidence to sanction the project was provided by the high-quality seismic data, a high degree of subsurface uncertainty remained (e.g., reservoir connectivity). Appraisal drilling was conducted in only one of the five fields. Therefore, a significant amount of subsurface appraisal was loaded into the development stage. The understanding and management of subsurface uncertainty has been crucial for the development, with early and effective data collection by use of wireline, logging-while-drilling (LWD), and coring programs; preproduction well-interference testing; and real-time data acquisition during the ramp-up period.