Hydrate Blockages in Flowlines and Subsea Equipment in Campos Basin
Authors: Freitas Alexandre M. , Lobão Anselmo C. , Cardoso Carlos B. 
Published: October 2008

Petrobras has been facing many challenges as it goes toward ultra deep waters in Brazil and one of the main concerns in subsea production is to avoid hydrate formation and blockage during operations such as production shutdown/restart and well workover.

This paper describes operational procedures carried out in Campos Basin to locate and dissociate gas hydrates plugs in subsea equipment and pipelines. Two cases are discussed. The first describes a hydrate blockage inside a 10 km long, 6" diameter flowline formed during a pull-in operation in Roncador field. The line was connected to a semi-submersible platform and a routine hydrostatic test using seawater was performed. After an attempt to clean up the line by reverse diesel circulation with foam pig, a hydrate plug in an upper part of the riser was formed.

The second case describes a severe blockage formed in both flowline and X-tree valves of a water injection well in Marlim field during a prolonged shutdown, probably due to gas segregation from reservoir.

The hydrate dissociation operations were successful and employed distinct techniques to conform to the particularities of each scenario.

Different depressurization schemes were employed. In Roncador, depressurization scheme involved foam pigs, nitrogen injection and a service rig. In Marlim, the flowline depressurization was achieved by means of a rather complex operation involving coil tubing and FPSO maneuvering.

Introduction

Natural gas hydrate is a nuisance in many production systems that operate at low temperatures and high pressures. They are solid structures composed of water and gas and depending on thermodynamic conditions, water molecules will form a solid cage entrapping gas molecules. The problem of the formation of these clathrates is well known by the petroleum industry and has been studied for a long time1.

Techniques to prevent hydrate plugging include insulating the flowline to keep the produced fluids warm, injecting thermodynamic inhibitors such as methanol/ethanol to lower the hydrate stability temperature, and/or blowing the system down to low pressures during shut-ins.

Although hydrates can plug off a flowline during normal production operations, more vulnerable are the transient operations, such as shut-in and start-up, where temperatures tend to be lower, pressures can be higher and water has time to accumulate in low spots.

In Campos Basin, most field developments in deep water has to rely on production flowlines to carry raw, unprocessed reservoir fluid from wells to production facilities. While this configuration lower the capital investment, it may pose an additional concern, which is the possibility of hydrate formation in the flowlines.

Earlier work2 has shown that, in a laboratory scale, it is possible to plug a multiphase flowline by hydrates and that the plugging potential is a strong function of water cut and crude properties. Petrobras experience in Campos Basin has shown that crudes have natural surfactant compounds that strongly stabilize water-in-oil emulsions. This behavior will reflect on hydrate-oil stability and may explain why no hydrate plugging has been reported in producing flowlines even during shutdowns and re-start operations.