Wax-On, Wax-Off: Understanding and Mitigating Wax Deposition in a Deepwater Subsea Gas/Condensate Flowline

Abstract The subsea Coulomb field is a two-well gas/condensate development in 7500 fsw, tied back to the NaKika platform in the Gulf of Mexico via a single 27-mile, 8" bare flowline. First production was in June 2004. The design basis employed continuous injection of monoethylene glycol for hydrate inhibition along with a "wax-in-place strategy"; this assumed a low rate of wax deposition, controlled through the use of inhibitor, such that solids accumulation during field life would not constrain production. Fluids from one well are significantly waxier than the well used in the design basis, but this was not known until April 2004. Prior to startup, predictions of the most severe deposition rate in the absence of inhibitor suggested a steady increase in flowline ?P to 3500 psi after 20 years of production. However, in reality the Coulomb flowline experienced a rapid increase in pressure drop to ~4000 psi within the first month of production from the waxier of the two wells, ultimately resulting in the temporary shut-in of that well. Correlation of field observations, transient multiphase modeling and laboratory experiments eventually determined that the deterioration in flowline performance was most likely due to accumulation of a highly viscous material, either a wax/glycol/ condensate emulsion or a wax slurry, stable at ambient seafloor emperature. Further work strongly suggested that burying the flowline in order to improve heat retention by the produced fluids might mitigate this phenomenon. This paper discusses the evolution of the technical justification to bury the flowline and the ultimate impact of the burial with respect to re-establishing (and ultimately increasing) production from the two wells. Introduction The "Coulomb" subsea gas/condensate field is located in the deepwater Gulf of Mexico, at a water depth of approximately 7500 feet. Production from two subsea completions flows 27 miles along the seabed through a single, 8-inch subsea flowline, tied to the host platform by a steel catenary riser (Figure 1). The two wells, referred to as C-2 and C-3, produce fluids with significantly different condensate/gas ratios (CGRs); production from C-2 is rather leaner (65 bbl/MMscf) than that from C-3 (200 bbl/MMscf). Monoethylene glycol (MEG) is injected at the tubing head of each well to provide continuous hydrate inhibition throughout the subsea system. Shortly before production was started up, analysis identified that the fluids from the C-3 well contained a higher wax percentage than those from the C-2 well, which had been used to develop the design and operational philosophy for the field. Shortly after startup, a steady increase in pressure drop was observed in the flowline/riser system; the pressure gradient was approximately twice that predicted by steady-state multiphase flow models. The high ?P in the subsea flowline was attributed at first to wax deposition; the backpressure imposed on the flowing wells caused a reduction of some 30% in the total production capacity of the system. Attempts were made to identify an effective paraffin inhibitor that might reverse the phenomenon, however none was found.