Subsea Production Optimization in Field BC-10 Offshore Brazil

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 26220, “BC-10: Optimizing Subsea Production,” by N.C. Sleight and N. Oliveira, Shell, prepared for the 2015 Offshore Technology Conference Brasil, Rio de Janeiro, 27–29 October. The paper has not been peer reviewed. The BC-10 asset, located in deep water offshore Brazil, produces heavy oil in the range of 16 to 24 °API. Mudline caisson separators with electrical submersible pumps (ESPs) are used to process fluids from multiple wells and boost them to the receiving floating production, storage, and offloading (FPSO) vessel. There are significant flow-assurance challenges in operating the asset. In this paper, two examples of production optimization for this field will be provided (further examples are available in the complete paper). BC-10 BC-10’s production comes from four fields located in water depths ranging from 1650 to 1920 m and is dependent on artificial lift. This summary focuses on optimizations involving the Ostra field. The subsea architecture that enabled the development of these separate reservoirs consists of multiple drill centers coupled to production manifolds. Manifolds are routed to caisson ESPs. These caisson ESPs will henceforth be referred to as MOBOs (derived from the Portuguese acronym for pump-boosting module). To minimize equipment costs, each field has only two production flowlines routed to the host: one is for production, and the second is for hot-oil displacement and production. In the case of Ostra, a third riser for gas separated subsea is also present. This design reduces the number of risers required. In line with this philosophy, there are only three oil-production trains and one gas separator on the host. Ostra Field Ostra consists of seven producer wells, with production collected by two manifolds and routed through two 8-in. intrafield flowlines to the artificial-lift manifold (ALM), which houses four caisson separator MOBOs. The operating philosophy is to run three units out of four, leaving the fourth unit as a standby in case of MOBO failure. Because the ALM is not located with permanent vertical access, MOBO interventions require the use of a rig capable of pulling the 140-t unit to surface. For this reason, having an installed spare is critical. The production manifolds allow one of two routings per well, which allows a flowline to be aligned to one, two, or more MOBOs; full bypass of the MOBO; and routing of hot oil for MOBO startup and planned shutdown from the surface by a dedicated choke. It is also possible to allow the 4.5-in. hot-oil supply line to be used for production. The 8-in. gas line features a common choke on the ALM to control backpressure on the MOBOs and a surface choke at the FPSO vessel as a second means of control. In practice, to avoid a well trip causing a rapid loss of MOBO pressures (with corresponding well-rate increases), the subsea-gas-line choke is used only in special circumstances, with daily control being performed by use of the topside boarding choke, which allows a much larger gas-storage volume and hence limits rapid pressure transients. The Ostra field has seen good pressure support through the first 5 years of operation because of a strong supporting aquifer, and it currently produces 60,000 to 70,000 B/D gross. Gas disposal was performed through an injection well deeper in the Ostra aquifer while gas export was commissioned.