In 1999, Welling and Associates conducted a study of 110 oil companies throughout the world. This study revealed that flow assurance was the most important tech-nical issue facing the oil and gas industry today. This is also reflected in the Deepstar program. Deepstar is a joint venture of a large number of oil producers and service companies to solve significant deepwater challenges in an organized fashion.
The goal of the early Deepstar group was to develop flow assurance solutions that would provide the ability to tie back deepwater (10,000 ft) subsea fields over significantly long distances (60 miles). The Deepstar committee has to date spent millions of dollars investigating flow assurance issues and it is clear that this goal is getting closer and closer.
What is this mysterious issue we know as flow assurance? An analyst once tried to provide a definition, and the answer covered move than three pages. Today, we have a common understanding that flow assurance covers the following topics in multiphase hydrocarbon production systems:
- Hydrates: the formation of ice particles in low temperature, high pressure flowlines
- Wax/asphaltenes: the deposition of solids onto the flowline, reducing the flow capacity through the line
- Slugging: the phenomena caused by instabilities of the gas and liquid interface and liquid sweep-out by gas inertial effects
- Erosion: wearing of the pipework and flowline wall due to solid particles such as sand or liquid impingement
- Corrosion: wearing of flowline wall thickness due to the chemistry of the produced fluids
- Emulsion: oil and water mixture at approximately 40-60% water cut that causes excessive pressure losses
- Scaling: solid buildup, especially onto the wellbore tubing, due to the chemistry of produced water.
These issues will determine the field layout of subsea developments, including the need for round trip pigging, riser configurations, gas lifting in the wellbore or at the riser base, and subsea chemical distribution. Flow assurance issues are exacerbated in deepwater because of high hydrostatic pressures and colder temperatures.
Slug acceleration and expansion is becoming an increasing problem as water depths grow. So how do we overcome flow assurance issues and provide the Deepstar ideal cost through effective ultra-long-distance tiebacks?
The first solution is to use chemicals: meth-anol or glycol to prevent hydrate formation, kinetic threshold inhibitors to delay the onset of hydrate formation and pour point depressants to prevent the formation of wax, corrosion and scale. The problem with chemicals is that they are expensive and they do not always completely solve the problem.
Many flow assurance solutions focus on pipeline insulation techniques. This involves keeping the produced fluid above the wax appearance temperature and/or the hydrate formation temperature. Special coating systems have been used for many years in the North Sea to keep flowlines warm.
The insulation systems have typically been multi-layered high-density polypropylene, which have been specially engineered to suit the rigors of reeled pipeline installation methods. Special facilities were set up in the North Sea to accommodate the market demand for these coating systems.
However, these coating systems did not meet deepwater requirements, either from an economic standpoint or from thermal conductivity standpoint. New coating/insulation systems are required that produce an enhanced performance in water depths greater than 2,000 ft. The original starting point for these systems was pipe-in-pipe, which uses an excellent insulation material (polyurethane foam), jacketed within a steel pipe.
Syntactic foam solutions were also developed using various densities of foam and including additional materials such as glass microspheres to provide enhanced thermal performance. More recently, the burial of flowlines has been used as an insulation methodology. The key factor in this instance is the ability to understand the amount of soil consolidation required, providing a given U-value.
The ultimate insulation system is vacuum insulated flowlines. This will provide the lowest U-value, but at a significant cost. These systems have been used with some success in wellbore applications. However, insulation systems still require two flowlines to a single well, thus allowing round-trip pigging, for flowline clean up.
A more cost-effective solution is to provide a mechanism to actually heat the pipe, to maintain heat in the line especially during the critical startup and shutdown operations. Heating can be provided by several methods:
- Regular hot oil flushing to remove wax build up.
- Water or crude oil circulation through the annulus of a pipe-in-pipe system.
- Electrical heating of the flowline.
Bundled flowlines provide a very simple way to provide heat to the flowlines via circulation systems. These have been used with a lot of success throughout the world for many years. There is still some doubt about the applicability of these systems for deepwater and ultra-deepwater. Hence, the focus has turned away from bundles to electrical heating of flowlines.
In 2001, Shell plans to install the first electrically heated flowlines in the deepwater Gulf of Mexico. If this proves to be successful this will be the first step on the road to meeting the target of long distance tiebacks of subsea systems. Other companies are working on new and innovative solutions associated with cold flow/slurry transportation of wax and hydrates. These new ideas, if successful, will carve the way for greatly reducing offshore capital development costs in the next five years.