Multiphase Hydrate Kinetics Model Extends Offshore Oil and Gas Field Operability

Abstract

Abstract An offshore oil and gas field undergoing a major production increment relies on a constant supply of Monoethylene Glycol (MEG) as protection against hydrate blockage risk. MEG supply pump trip would initiate an emergency shut down of the entire production system, both gas and oil. Novel hydrate research on hydrate growth rate was applied to estimate the survival time from loss of MEG to full pipeline blockage. Hydraulic multiphase flow assurance transient modelling of both associated and nonassociated offshore gas gathering system was utilizing the novel hydrate kinetic module tuned to lab data for gas-dominated production systems. Analysis was performed considering different periods of total MEG loss and reinstatement, to predict hydrate formation volumes and hold-up within the gas network. In addition, periods of MEG under injection were considered, along with effects on ramp-down and subsequent ramp-up. Additional sensitivities were performed considering the ambient temperatures and changes to hydrate equilibrium curves. Finally, modelling parameters including hydrate cohesive/adhesive forces and prediction of entrainment of water were considered to ensure robust conclusions. Temporary but complete MEG loss shows that hydrates begin to appear soon after MEG disruption, and hydrates tend, predominantly, to deposit on the pipe wall. The risk of a complete pipeline blockage after an 8-hour MEG disruption will depend on pipeline diameter and gas flowrate and composition. Small diameter flowlines transporting lean gas (no condensate phase), tend to accumulate hydrate faster due to the absence of the oil layer, giving greater contact between gas and water phase. Larger diameter trunk lines do not show any significant hydrate accumulation even after an extended level of MEG disruption. In most cases, hydrate accumulation will be eliminated during re-start of the MEG injection. The analysis allows identification of pipelines most at risk of hydrate blockage, and allows development of operating procedures to protect the system if loss of MEG occurs. Overall, it allows the specification of less conservative shutdown conditions and eliminates the potential loss of total field production by loss of MEG supply. The analysis is based on experimental hydrates research from the University of Western Australia and is the first model developed specifically for gas dominated production fluids. It represents a previously unavailable methodology to predict evolution and distribution of hydrate phase within both fluid and pipe wall, time required for hydrates to first appear with loss of inhibition; the duration of hydrate accumulation to grow to a dangerous level and time for dissociation on restoration of MEG supply.