Brazil Parque das Conchas Project Sets Subsea Separation, Pumping Milestone
- Joel Parshall (JPT Features Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 2009
- Document Type
- Journal Paper
- 38 - 42
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As first oil flowed on July 12 at the Shell-operated deepwater Parque das Conchas development offshore Brazil, it marked a major advance in the production of Brazil’s abundant heavy-oil reserves and became the world’s first full-field development based on subsea oil and gas separation and subsea pumping.
Situated 75 miles southeast of Vitória, off Espirito Santo state, Parque das Conchas (formerly known as BC-10) lies in approximately 4,900 to 6,500 ft of water at the northern edge of the Campos Basin (Fig. 1). Parque das Conchas in its first phase will produce from three fields, with oil ranging in gravity from 17 to 42°API. The fields will produce through subsea trees and flowlines tied into the centrally located floating production, storage, and offloading vessel (FPSO) Espirito Santo (Fig. 2). Turret-moored in 5,840 ft of water, the double-sided FPSO is equipped to process peak daily project production of 100,000 BOE, with 1.4 million bbl of oil-storage capacity. Parque das Conchas is a joint venture of Shell (50%), Petrobras (35%), and ONGC (15%).
The development grew out of a substantial exploration and appraisal program, in which Shell drilled 13 wells and made six discoveries. The project was declared commercial in 2005, and major contracts were awarded in November 2006. For Shell, Parque das Conchas is the first Brazilian project the company has taken all the way from exploration to production, as opposed to inheriting a project from another operator or initiating a project that it had to turn over to someone else to operate.
Challenges to Project’s Economics
“There were a number of challenges we faced to make the project economic,” said Kent Stingl, Parque das Conchas project manager for Shell. “We had heavy oil in relatively low-pressure reservoirs in an ultradeepwater environment. Hence, we had to determine how to pump from this depth and process on the production facility. But there was more to it than that. There are four dispersed reservoirs, small to medium in size, with widely divergent oil gravities and different gas/oil ratios (GORs). We needed to find an economic way of commingling and bringing production from the various reservoirs back to a central facility, with artificial lift (AL) required and subsea gas/oil separation for some reservoirs.”
A further challenge was that the reservoirs, though in deep water, are only approximately 3,300 ft beneath the mudline. “Starting from vertical at the seafloor, we had to kick the wells out at a tremendously high angle to drill the horizontal wellbores required to drain these reservoirs,” Stingl said. “We operated from only a few drilling centers to minimize the need to move the rig. So these horizontals extended more than 3,000 ft, and all were completed with gravel packs.”
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