Global perspective on flow assurance

Martin Brown

July 21, 2014

FPSO, deepwater riser and subsea architecture. Photos from Flowsure. 

Ensuring successful fluid flow has always been at the heart of the oil and gas industry. However, it is only in the last 20 years that flow assurance has become a classification in its own right. The origins of the term are not known, however, in the early 1990s, the term garantia do escoamento, meaning guarantee of flow, was coined by Petrobras.

Since then, flow assurance has become a key term associated with new and existing developments, and is now generally considered to address all issues critical to ensuring the multiphase transport of fluids, from reservoir to processing host.

The simultaneous transport of oil, gas, and water through pipelines is now standard practice for new developments. Ensuring the successful transit of multiphase fluids over significant distances is crucial to ensuring development profitability. The financial implications of a production interruption, as a result of a loss of flow, can be catastrophic. Flow assurance is, therefore, not only a major technical challenge but a serious economic concern.

Flow assurance techniques include the application of analytical multiphase software, to help understand and evaluate many different types of system. The analytical insight provided can be used to develop technologies which enhance the efficient transport of multiphase flow, making it possible to develop fields which would otherwise be uneconomic.

Flowsure has noticed that global flow assurance efforts are increasingly becoming focused on a number of key development types.


Deepwater currently accounts for about 7% of total conventional production but, year-on-year, the proportion of global discoveries that are classed as deepwater is on the increase.

The key regions for deepwater discoveries are North America (e.g. Gulf of Mexico), Latin America (e.g. Brazil) and Africa (e.g. Angola).

Deepwater flow assurance is focused on managing the low ambient-temperatures and high-pressures on the seafloor. In deepwater remediation costs are very high and any shutdown resulting from a flow assurance incident can be both lengthy and costly.

Subsea wellhead and muiltiphase flow in wellbore.

Managing hydrates during a system shutdown is a crucial operation, which requires complex analysis. Using chemical inhibition is not always the most economical option and complex “preservation” sequences involving partial depressurization and system flushing usually need to be developed. As deep-water risers are significantly longer than conventional risers, the flow instabilities associated with slugging can be significantly magnified.

Both the slugging characteristics and the conditions under which slugging is initiated must be analyzed and defined so that effective mitigation measures can be developed. The interface of flow assurance with the topside facilities is there- fore critical and facilities for handling slugs during normal operation, start-up and system depressurization need to be provided and sized correctly. Where this is not possible, the use of innovative solutions including intelligent chokes need to be considered.

Heavy Oil

Worldwide heavy oil resources (both onshore and offshore) have been estimated as in excess of 7.4MMbbl (2009).

Heavy oil production is well established in onshore and shallow water fields. However, the production costs are higher than more conventional resources, and when situated remotely and in deep- water this effect is heightened.

Heavy oils are characterized by high viscosity and a low API gravity. Heavy oil is typically defined as an oil exhibiting an API gravity < 22°. These factors mean production and transportation of heavy oils can be a major flow assurance challenge.

Heavy oils can be complex and fluid properties difficult to predict using conventional software. Care needs to be taken to ensure simulated fluid properties represent measured laboratory data. Heavy oils are also susceptible to forming emulsions which can significantly increase viscosity.

The effective viscosity management of heavy oils is therefore a key flow assurance issue. The most effective solutions typically involve using heavily insulated/ heated pipeline systems and or diluents.

Retaining heat by using high performance passive insulation (OHTC < 1 W/m2K) systems has become common practice in many types of offshore development. In heavy oil systems, heat retention is critical, as small reductions in temperature can greatly increase fluid viscosity resulting in increased pressure drop and reduced hydraulic capacity.

Multiphase flow in subsea flowline. 

Actively heated pipes are another option for heavy oil systems. These may take the form of pipeline bundles heated through the circulation of hot fluid or electrically heated pipelines. The latter represents relatively new technology, which is becoming more widely utilized.

Using diluents to reduce viscosity (10%-50% by volume) can be expensive, due to the requirement for large umbilicals to transport the chemicals, and needing high chemical storage volumes.

Laminar flow drag reducers have been proven to work on heavy oil fields in the US. These are effectively a form of demulsifying surfactant reportedly reduce the apparent viscosity to around 15-25% of that with- out the chemical.

At Flowsure our fluids experts have been involved in projects involving water- assisted pipeline transport of heavy oils. Water forms a lubricating layer on the pipe wall while the viscous heavy oil is transported in the inner core of the flow. This approach significantly reduces the energy required to transport these fluids.

Heavy oil deposits are usually low energy and artificial lift with electrical submersible pumps (ESPs) is a proven technology. However, ESP efficiency declines as oil viscosity increases. ESPs therefore work most effectively in conjunction with viscosity lowering techniques. An ESP’s impact on fluid shearing and the oil’s emulsion forming tendencies must also be taken into account. A hydraulic submersible pump (HSP) driven by hot water may also pro- vide an attractive solution.

Flow assurance also needs to consider the transient behavior of heavy oil systems, in addition to steady state. The issues associated with heavy oils are similar to those of more conventional fluids, but the emphasis on unusual fluid characteristics needs to be addressed. For example, during a long shutdown, a conventional system would be depressurized to prevent hydrate formation. For heavy oils, the resultant lower pressure would tend to lead to an increase in the oil viscosity through gas liberation. An alternative such as hot water or diesel flushing is an option.

Typical hydrate prevention strategies can be detrimental to viscosity management. The start-up of a shutdown system and handling of cold viscous fluids needs to be considered if thermal methods are applied.

Figure 1: HP/HT definition.

High-pressure / high-temperature (HP/HT)

As technology allows the industry to locate and drill deeper discoveries, it has to contend with the associated higher pressures and temperatures. The development of HP/HT fields has become common place in the last five years, as conventional developments have waned and demand has increased. Various definitions for HP/HT fields exist but, typically, these can be classified as shown in Figure 1.

The flow assurance issues associated with HP/HT fields are similar to those of other more conventional fields. However, due to the nature of the reservoirs, these issues tend towards the extreme. Key production chemistry issues include: hydrates, and downhole scale and salt deposition. Continuous wash water may be required at production wellheads to prevent salt deposition downstream of the chokes.

HP/HT fields usually include a dual purpose cooling / warming spool at the wellheads to protect the pipeline design from excursions. The spool allows highly efficient heat transfer and has a cooling duty to minimize temperatures during steady state operation. During start-up, very low temperatures can be generated as the gas cap is blown down, therefore the spool has a warming duty. This helps to minimize cold start durations and optimize chemical injection usage.

Selecting pipeline materials in a HP/ HT environment, where using corrosion inhibition becomes less reliable, is also important. Where HIPPS is employed, transient analysis of system behavior is performed to define set points and system design pressures.

HP/HT developments are also increasing in deepwater areas, such as West Africa and the Gulf of Mexico. In these environments, the requirement for bespoke solutions to cope with the extremes in temperature and pressure has to be considered in tandem with limitations on subsea design at the deeper water depths.


A US Geographical Survey (USGS) study estimated that the Arctic could hold about 13% of the world’s undiscovered oil reserves and as much as 30% of the world’s undiscovered natural gas reserves.

Typical Arctic developments include Hibernia (concrete gravity structure), Terra Nova (reinforced FPSO) and White Rose (reinforced turret moored FPSO). Flowlines and wellheads are reinforced to protect against iceberg scour and well- heads are typically located within glory holes on the seabed.

There is a great deal of potential for multiphase developments in the Arctic. However, due to the combination of remote location (long distances to shore), harsh environmental conditions, and a lack of existing infrastructure, it also presents the most complex flow assurance challenges.

The potentially long tie-back distance (>500 km) could be four to five times greater than any existing large diameter multiphase pipelines. This means that existing multiphase flow technology and experience is likely to be tested to its limits.

Rough seabed (due to iceberg scouring) can lead to liquid accumulations and subsequent slugging issues. Sub-zero temperatures represent an issue in terms of hydrate, wax, and ice formation. Flow assurance needs to be considered as a life of field solution. All steady state and transient operations should be assessed and a robust system design with proven operability sought. It may be that multidiameter pipelines are used to pro- vide the required operability over a range of flowrates and fluid compositions. Future Trends The industry has, over the last decade, seen a huge increase in the development of technically complex offshore fields. Flow assurance, as an engineering discipline, has grown in tandem with this trend. As offshore developments become more technically challenging, under- standing key flow assurance issues is paramount to ensuring optimum system design and operability.

To realize the potential of some of the development types outlined above, it is certain that more innovative and bespoke solutions will be required. It is likely that these will involve subsea processing, electrically heated pipelines, and cold flow.

Flow assurance will play a fundamental role in solving major industry challenges and servicing the global market going forward.

Martin Brown is a Chartered Chemical Engineer (FIChemE) with over 30 years’ experience in the upstream oil and gas industry. He is known as a flow assurance technical authority, with specific expertise in HP/HT, deepwater, Arctic developments, and long distance subsea tie-backs. Before establishing Flowsure, Brown worked for a number of major operators and engineering consultancies.