In design of subsea production systems, assessment of slugging has typically focused on the liquids-handling capability of topsides facilities. However, recent field experience in the deepwater Gulf-of-Mexico indicates that the gas surges behind liquid slugs, rather than the slugs themselves, can be more problematic. Gas surging due to slugging is particularly problematic for "full" subsea production hubs with minimal spare gas compression capability, which if uncontrolled, can lead to topsides trips and production constraints. Herein, we assess the capability of modern slug-tracking models to capture the field-observed slugging, with particular focus on gas surging. Additionally, potential strategies for slug mitigation are explored, involving computation of alternative operating conditions as well as analysis of hardware modifications via coupled subseatopsides modeling.
In general, a standard design approach for slug-handling has been to size inlet separators to handle the largest liquid slug volumes anticipated. Typically, the design-case slug size is driven by either terrain-generated slugs or liquid surges due to transient operations (e.g. start-up, rate change, blowdown, etc.). In contrast, hydrodynamic slugs are characterized by a minimal liquid volume (e.g. 5-10 bbls), which is negligible with respect to the inlet separator size. Nevertheless, recent operational experience with Deepwater fields in the Gulf of Mexico has indicated that the gas surges associated with hydrodynamic slugs are potentially problematic for topsides facilities and control. Hence, the focus of this study is on modeling and control of gas fluctuations associated with slugging.
As a representative case study, we analyze here an oil field operated by SEPCo in the deepwater Gulf-of-Mexico. This subsea system currently produces via 3 subsea wells in nearly 4000 ft water depth, tied back approximately 18 miles to a hub platform via 8" × 12" pipe-in-pipe dual flowlines. As the field matures, slugging has become increasing problematic, causing
pressure relief flaring,
test separator metering difficulties, and
shutdowns due to pressure-high topsides trips.
Gas-handling difficulties are due in part to the production of a subsea system with inherent fluctuating flowrates (unlike direct-verticalaccess wells) into a full hub facility, with minimal spare gas compression capacity.
For surveillance of existing fields and design of future systems, it is critical to predict the slugging potential of generalized production scenarios, using validated multiphase flow prediction tools. Additionally, offline evaluation of possible operational solutions is necessary, to determine whether topsides hardware modifications will be necessary for future production. In response to these challenges, the primary objectives of this study are summarized as follows:
Analyze flow regime maps to predict the slugging envelope
Assess whether Olga2000 modeling captures the field observed slugging behavior
Develop and analyze potential operational solutions for slug mitigation
The slug-tracking feature of the multiphase flow simulation package Olga2000 is used for all computations of slug-induced flow transients, during otherwise steady production. Compositional PVT data is based on field samples of the produced well fluids, tuned to match the measured fluid properties of GOR~800 scf/stb and API~28°.