Economic evaluation of an accelerated, deepwater development is critically dependent on reliable, early estimates of hydrate formation conditions for produced fluids. Current thermodynamic models for hydrate formation calculate satisfactory pressure-temperature curves from the composition of a gas or gas condensate; however, they poorly predict hydrate formation conditions for a black oil. In addition, these models do not adequately predict inhibitor amounts, especially for methanol, or the quantitative impact of produced water salinity on inhibition. Steady-state multiphase flow simulation of an example ultra deepwater project shows that an uncertainty in hydrate prediction temperature of ~ 10 F can result in a step jump increase in CAPEX; e.g. designing the subsea production system for PipeInPipe insulation when external insulation of the pipeline/riser would be sufficient.
There are a number of hydrate prediction programs currently available for oil and gas applications. Generally they give good agreement when predicting the thermodynamic hydrate formation conditions (P/T lines) of natural gases and condensates; however, for black oils the predictions show considerable inconsistency (~10 F range). The reasons for these inconsistencies are not understood.
An important aspect of the hydrate problem is the role of the inhibitors and how they interact with the black oil/produced water system. Besides added inhibitors such as methanol and monoethylene glycol (MEG) there are also the naturally occurring inhibitors - the dissolved salts in the produced water. Hydrate predictions for mixed inhibitor systems are not accurate.
In the exploration and appraisal phases of an ultra deepwater oil project, a major source of uncertainty is the cost of hydrate prevention, both CAPEX and OPEX. The CAPEX items include insulated subsea production equipment (trees, manifolds, jumpers, pipelines and risers, etc.), subsea active heating systems, umbilical lines, and topsides inhibitor pumps and storage tanks. The cost items associated with OPEX include inhibitor amounts used through the entire life of the project, shipping of inhibitors, remediation of hydrate plugs and oil contamination. Better hydrate predictions andimproved estimates of the uncertainties will reduce the risk of making investment decisions.
This paper describes the issues of hydrate inhibition with the aid of a realistic model project based on a notional 20 year West African field that was previously described by Remery and Kodaissi1 in their paper on flexible riser systems for ultra deepwater. In particular, I use their production profile (Fig. 1) in a subsystem consisting of two 5,000 ft (below mud line) vertical wells connected to a 10,000 ft horizontal pipeline and 8,000 ft vertical riser (Fig 2). This production profile is representative of a reservoir with a strong aquifer drive or alternatively, one with pressure maintenance by seawater injection. The resulting production profile (Fig. 1) shows peak oil production of 25,000 barrels per day for years 2, 3, and 4 followed by water breakthrough in year 5. Thereafter the total liquid rate increases but at the expense of increasing water cut.
