Offshore constructions costs can be very high when the operation requires the use of additional vessels and support tugs. This was the case in 2016, when some of the riser bellmouths needed to be replaced on one FPSO located offshore Brazil. The initial bellmouth change-out plan included an installation vessel plus support tugs to hold the turret moored FPSO in position. As a result of the current cost constraints in the offshore industry, it was necessary to challenge the conventional way of working and to re-evaluate the construction methodology. This paper presents the methodology used on the FPSO bellmouth change-out, where all operations were conducted from the FPSO, without the need for the installation vessel or support tugs. The FPSO for this case study is located in the Campos Basin deepwater, in 1485m water depth, and approximately 70 kilometers east of Victoria, Brazil. The FPSO started production at its current location in May 2010. The unit has a maximum oil production capacity of 100,000 bopd, and a gas processing capacity of 70 mmscfd. Oil is stored onboard and offloaded through a tandem moored shuttle tanker. The gas is compressed and exported from the FPSO via a flexible riser, which connects into the Petrobras gas export system. The bellmouth change-out operations consisted of replacing the bellmouths of each of the 8 production risers. The paper will focus on engineering design and offshore operation phases to implement the bellmouth change-out in a safe, cost effective manner.

Offshore project capital costs have increased by an astronomical 400% forcing IOC's, NOC's and independent players to re-evaluate the feasibility and the profitability of some major developments. A decade long boom is now confronting unpredicted reality, altering the offshore development landscape and resulting in fewer opportunities and major consolidations in owners and contractors. Some owners are now shifting focus to brownfield and marginal field tie-backs to eliminate costs and risks associated with new installations. This paper explores one of those opportunities, namely turning Floating Production Units (FPU's -Semi, TLP, SPAR) into hubs, where various field owner/operators share production through the same FPU. Typically, hub developments are contracted under Production Handling Agreements (PHA). The PHA provides for price tariffs on produced oil, water and gas and is collected as the field owner/operator produces. Tariffs are paid for actual production which reduces reservoir production risk for large capex investments. Hub developments offer the field owner/operator the following value:• Lower developmental CAPEX investment • Reduced operating costs • Accelerated development schedule • Risks and liabilities for decommissioning and poor well performance are reduced or eliminated.Aspects of selecting the appropriate FPU are considered while presenting the suitability and limitation of each type for appropriate production sharing models. The paper will present a recent case study for a Semi-submersible designed with reserve topside, hull and mooring system capacity to meet tie-back requirements. The Semi-submersible is located in the deepwater Gulf of Mexico, at 6060 feet water depth, and approximately 145 miles southeast of New Orleans. The Thunder Hawk Semi-sub came online in July 2009. The unit has maximum oil production of 60,000bopd, and gas processing of 70mmscfd. Oil and gas is exported from Thunder Hawk via Steel Catenary Risers (SCR's) that connect into the export system. The recent tie-back to Thunder Hawk consists of three (3) wet insulated 8Љ SCRs, 8,500 psi. Three new wells are tied to the facility with capacity to produce up to 20,000 bopd each. The paper will focus on the technical and commercial constraints and opportunities employed to implement the tie-back, namely: engineering design, regulatory requirements, and production sharing philosophy.

No abstract