Schlumberger

Case study: Commercial Potential of a Heavy Oil Reservoir in Ultradeep Water Revealed

Schlumberger conducts testing with an ESP for Petrobras to determine the producibility of a large field in 2,500-m waters

Challenge: Determine whether a highly viscous oil can be produced economically from an ultradeep, low-temperature well.

Solution: Perform an integrated downhole test that employs an ESP to ensure the flow of reservoir production to the surface and accurate data acquisition.

Result: Accomplished all client objectives with a conclusive evaluation provided through an expedited process free of incidents or downtime.

In 2007, before the presalt discovery offshore Brazil, there was greater interest in the heavy oil reserves there. These reserves could contribute to self-sufficiency in oil production, but producing the reserves, especially in ultradeep water, is technically and economically challenging. Efficient well testing and reservoir characterization procedures are key aspects when evaluating the commercial viability of a discovery.

At the time, preliminary geological studies of the Xerelete field offshore Brazil indicated that its total area would be more than 26 square kilometers and that it could possibly have an in-place volume of 1.4 billion bbl of oil equivalent.

Determine the commercial potential of a heavy oil well in ultradeep water

Petrobras, in collaboration with partners Devon and Total, requested immediate well testing to evaluate the commercial viability of the 3-RJS-648 well in the Xerelete field.

Given that test training had not been included in the planning stage of the well, the short time available for testing, water depths of just under 2,500 m, and the necessity of positioning the ESP just above the seafloor, the request could not be treated as standard heavy oil well testing in Brazil.

For this type of offshore well, test preparation—including a QHSE review; test design; equipment selection and preparation; transportation and logistics; rig-up; and development of a contingency plan to restart the ESP after a static period—would take two to three months. Through an integrated Petrobras-Schlumberger team effort, expedited test preparation was accomplished in two weeks.

Apply a wide complement of services and technologies to deliver conclusive answers

In order to determine the rock-fluid system characteristics, evaluate the well potential, and quantify the reserves—and based on the high probability that the well would not flow naturally at 2,460-m water depth—pressure-production well testing with artificial lift would be required.

After analyzing alternatives, the collaborative team selected a downhole test system with an ESP to ensure the flow of reservoir production to surface as well as to acquire accurate data.

In making its decision, the team considered the probable volume of drilling fluid lost to the formation while drilling, the range of operation required of the ESP, and the flow rate desired for testing.

Several analyses were evaluated to decide the pump set depth. Based on simulations using PIPESIM steady-state multiphase flow simulator and DesignPro ESP design software, the ESP string was placed just above the blowout preventer. Then, the team developed a contingency plan to inject diesel fuel using coiled tubing if necessary.


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