The ‘Pseudo’ Dry Gas (PDG) subsea concept is being developed to dramatically improve the efficiency of subsea gas transportation by removing fluids at the earliest point of accumulation. The technology will increase the geographical reach from receiving gas terminals, allowing asset owners to prolong production life without the need for more expensive design solutions. This paper will provide an overview of the innovative technology, demonstrating that a 200 km plus tie back can be achieved, without compression.
Increasing the distance of subsea tie-backs increases the liquid inventory, with constraints on pipeline diameter for slug free flow. The PDG concept is based on a main gas line integrated with piggable gravity powered drain liquid removal unit and pumps (a smaller fluid line transports separated liquid). Multiple units are specified to drain liquids as they condense in the line, maintaining near dry service. Liquid free operation removes the constraint on pipeline diameter. Specification of a large diameter pipe (within installation limits) reduces backpressure on the wells, enhancing recovery. Minimum stable flow limits are removed, improving tail end recovery.
Current stranded gas development options (subsea compression, floating facilities, FLNG) generate a step change in costs which can make a project uneconomic. This is even more acute in mature and semi-mature basins where existing gas processing facilities / LNG terminals already exist offshore or onshore along with sunk costs from the exploration. A case study for a 185 km pseudo dry gas subsea tie-back to shore demonstrates the PDG concept feasibility. This result is used to argue that the PDG concept should be included in the suite of subsea processing options considered by Operators in early field development planning.
Although the commissioning of a floating production system (FPS) generally takes place between the “mechanical completion” and “first oil” stages, commissioning activities begin long before then. LLOG Exploration’s Delta House floating production system (FPS) looms large over Kiewit Offshore Services’ fabrication yard in Ingleside, Texas.
Shell and SBM Offshore won recognition for their Gulf of Mexico Stones field development. The OTC Distinguished Achievement Award will be presented during a luncheon on 1 May at the Offshore Technology Conference in Houston. Gene Kouba was recognized with the Projects, Facilities and Construction award during ATCE. OTC recognized three figures who have contributed to facilities engineering: Dendy Sloan, Jim Brill, and Ken Arnold. They were recognized with the Distinguished Achievement Awards for their technical and leadership contributions to the industry.
The SPE Gulf Coast Section’s Project, Facilities, and Construction study group is hosting a series of lectures, “What Have We Learned About Host Selection in Deepwater GOM After 20 Years of Being Off the Shelf? The development of compact topside processing plants for floating, production, storage and offloading (FPSO) vessels is a growing industry trend that can reduce operating and capital expenditures over the life of the vessel, a researcher and scientist said recently. Expenditures for floating production systems are expected to more than double in the next five years. This growth is driven by multiple factors. Investments in floating production systems are expected to increase sharply over the next five years, driven by a surge in installations.
With events such as the BP Macondo blowout in the US Gulf of Mexico (2010) and the Pemex Ayatsil-C platform accident (June), the safety risks inherent in oil and gas projects are evident. Although the commissioning of a floating production system (FPS) generally takes place between the “mechanical completion” and “first oil” stages, commissioning activities begin long before then. LLOG Exploration’s Delta House floating production system (FPS) looms large over Kiewit Offshore Services’ fabrication yard in Ingleside, Texas. The ultimate success of a deepwater project depends on phases from early concept selection, design, construction, commissioning, and startup to operation. However, the boundaries and transfer of responsibilities may not be sharply demarcated between phases.
Lessons Learned as World's First Cell Spar Laid to Rest After 10 years, the world’s first cell spar, Anadarko’s Red Hawk, was decommissioned. It remained the only cell spar fabricated and again made history as the deepest floating production unit ever decommissioned in the GOM. For Anadarko, the secret of the “design one, build many” approach to offshore production facilities is to control its enthusiasm for change. The company’s experience with eight operated spars shows the benefits gained with this approach.
Siemens and GE are among the companies discovering the power of an open-source innovation community to offer solutions for significant oil and gas industry challenges, such as improved corrosion monitoring. ABS granted Approval in Principle to new designs for a floating production storage and offloading hull, a self-elevating unit for a mobile offshore drilling unit, and a tension-leg platform. Whether you are involved in the design and construction of new facilities or the decommissioning of existing facilities, having a solid understanding of decom makes a lot of sense. Are you ready as all around the world offshore facilities have reached, or are reaching, the end of their design life? This study presents an overview of the structural response and failure mechanism of three-sided protected beams and proposes design solutions.
These balls have the potential to alter how pipeline inspections are done, and a consortium of pipeline operators and industry experts in North Dakota is examining just how well this emerging technology can handle the small-diameter pipelines in the area. Scheduled for startup in 2022, the FPSO is expected to produce up to 220,000 BOPD on the development offshore Guyana. Liza is one of eight discoveries ExxonMobil has made in area. The Hess-operated field, which drew first oil in January, is expected to produce 80,000 BOPD as production ramps up this year.
A shut-in subsea flowline is believed to be the source of the spill on Husky Energy’s SeaRose FPSO offshore Newfoundland and Labrador. The spill is believed to be the largest in the history of the Canadian province. The deal gives Equinor exploration parcels in the prolific Jeanne d’Arc Basin, near its existing discoveries offshore Newfoundland and Labrador.