Accurate PVT information contribute significantly to improve metering uncertainty for either topside or subsea business and for multiphase and/or wet gas meters. This is because flow rates need to be provided at standard conditions. Usually, the subsea meters have been set-up using PVT information collected from samples taken during drilling. Rarely this data have been updated after meter installation due to lack of access to quality representative samples. The same issue is raised from a flow assurance point of view by numerous tiebacks to a main subsea production line and with little challenge on the compatibility and effects due to poor access to representative samples.
This paper will address the issues regarding access to well stream fluids, ability to capture representative samples, sample handling and storage, and the data needed to recombine the samples and possibilities to implement solutions to these challenges.
If subsea multiphase meters serve as the operator' eyes and provide volumetric flow rates of oil, water and gas phases. The data provided by the meters is used also for flow assurance, allocation, and production management and to gain understanding of the reservoir structure, hence the importance of maintaining the measurement over time. As any meters, the measurements are reported at line conditions, where the measurements are taken, usually near the subsea tree, but the operator usually requires the meter to provide flow rates in standard conditions as well. These line conditions measurements are then converted to standard conditions using a dedicated or not PVT model. Depending on the fluids, the method used can have an impact of up to +/-30% uncertainty at standard conditions (Joshua Oldham, Exxon Mobil, at Subsea Tieback 2008). In order to reduce this source of uncertainty, the EOS must be updated as needed. If wells are commingled subsea the only way to gather, the information needed is to sample the fluids at meter conditions in a representative state and recombine them in the lab. The remainder of the paper will describe the innovative tools and methods needed to achieve this.
Oil and gas field operators are increasingly moving into deep and ultra-deep waters to develop new fields. This has encountered considerable success in Brazil, West Africa, and Gulf of Mexico despite the increasing need for more reliant subsea production infrastructures. This trend is also very strong in Asia Pacific with Australia and Indonesia, and lately Malaysia. The vast area full of water in Asia Pacific is only at the beginning of this new endeavor. Increased water depths, longer tiebacks, complex reservoirs and the continuous effort to reduce the cost of the subsea infrastructure, while still ensuring the highest possible recovery rates, raise new challenges in terms of reservoir and production management, flow assurance, and enhanced oil recovery. This is becoming very important with the development cost of such field going way above estimation and in the way slowing down the expansion or the growth of this subsea business for the good of everybody.
Pressure and temperature met in these reservoirs are also higher and higher versus time and the fact that production needs to be reported in standard conditions (usually around 14.7 psia and 60 DegF) create anadditional challenge. In this scenario, subsea sampling is rapidly becoming a simple and effective way to gather samples of the produced fluids through the field life, enabling accurate measurements of their properties and the changes that occur through the years.