When dealing with flow assurance, engineers try to balance perceived risks of a new development with the required capital expenditure.

For those working in the global oil and gas industry, flow assurance is an all-too-familiar term, adopted as a universal marketing cry by engineering design and construction companies alike. The term was coined by Petrobras in the early 1990s in Portuguese as Garantia de Fluxo, meaning "guarantee the flow," which was subsequently translated to the well-known expression "flow assurance." The term originally covered only the thermal hydraulic and production chemistry issues encountered during oil and gas production.
In recent years, flow assurance has become a vogue subject, and with this popularity, it now includes a multiplicity of other issues that can affect extraction of oil and gas. As a result, the term is now
synonymous with a wide range of issues:

• system deliverability - pressure drop versus production, pipeline size and pressure boosting;
• thermal behavior - temperature changes, insulation options and heating requirements;
• production chemistry - hydrates, waxes, asphaltenes, scaling, sand, corrosivity and rheology;
• operability characteristics - start-up, shutdown, transient behavior (e.g. slugging) etc.; and
• system performance - mechanical integrity, equipment reliability, system availability, etc.

The growing importance

Recently, flow assurance problems encountered in oil and gas production have become more onerous, leading to increased industry awareness. This is the case particularly offshore, where low temperatures, remote locations and great water depths of subsea environments conspire to exacerbate problems such as blockages through hydrate formation or wax deposition or topsides' facilities shutdowns due to severe slugging. The ramifications of these events can be very serious, incurring significant intervention costs and substantial production revenue losses.

But why have flow assurance difficulties worsened recently? The explanation lies in the changing face of the offshore industry. In mature provinces, such as the North Sea, average field size has decreased markedly such that small fields (typically 10 million bbl), are the mainstay of activity. For such small accumulations, economic hurdles can only be met if development costs are kept very low compared to historical levels. As a result, these small fields often are developed with long subsea tiebacks to existing infrastructure, pushing boundaries of flow assurance design.

At the other end of the spectrum are the frontier deepwater provinces, such as the Gulf of Mexico or West Africa, where the field size is much larger (typically 250 million to 1 billion bbl) and able to support a much higher capital investment. However, the flow assurance difficulties are still quite pronounced due to the inherent difficulties in producing from great water depths, often in excess of 3,300 ft (1,000 m).

The dilemma: risk versus cost

All oil and gas fields can be developed to minimize flow assurance problems and maximize overall production and availability. But it is well known that increasing the robustness of a system to very high levels implies increased equipment costs, which ultimately makes the project uneconomic. Hence, it is necessary to strike a satisfactory balance between the capital investment requirement and an acceptable level of risk. This is easier said than done because of the subjective nature of risk and varying perceptions of risk among those involved in the design process.

For example, a new field development may operate inside the hydrate risk zone (Figure 1, position A) in the first year of production because of low production rates and operating temperatures. This could be a temporary state; in later years, the number of producing wells will have increased as more wells are drilled, the average water cut will increase1, and the operating temperatures will rise, moving the system away from the hydrate risk zone.

Because of the temporary nature of the risk, and the low levels of water early in field life making the formation of a hydrate blockage unlikely, some will argue that this is acceptable. However, other more cautious types, mindful of the sensitivity of the overall economics to successful early production, may take the contrary view. They may recommend increasing insulation levels on subsea pipelines to move the system outside the hydrate risk zone (Figure 1, position B) thus reducing risk.

Who is right? The answer is highly subjective and impossible to answer before the event; which way you vote depends very much on your level of exposure to the potential risk.

Another example of the subjective nature of evaluating flow assurance risks is in the design of flowline-riser systems for stable operation free from slug flow. Offshore, a common configuration is a multiphase pipeline transporting gas and liquid supplied by a number of production wells at one extremity to a central processing facility at the other extremity. Fluids are conveyed from the seabed to the processing facility via a production riser.

These systems are susceptible to a form of instability that can lead to large surges in the liquid and gas production rates. If the topsides processing facilities are not adequately sized, this can result in equipment trips and unplanned shutdowns. In some circumstances, the magnitudes of these surges can render a system inoperable, necessitating costly equipment modifications such as retro-fitting a larger slug catcher.
This instability has various names in the industry, including "severe slugging," "riser-base slugging" and "riser-induced slugging." Figure 2 presents a schematic of the process of severe slugging. The base of the riser is periodically blocked with liquid, which prevents flow. After a period of time (usually in a few hours) flowline pressure has increased to a sufficient level to expel the liquid in the riser in one large liquid slug. This is then followed by a large gas surge produced as the pipeline blows down to a low pressure. As the gas rate drops off, liquid begins to accumulate at the base of the riser, and the cycle is repeated.

Figure 3 shows some predicted time traces generated from transient simulations with a leading multiphase flow simulator applied to a deepwater oil and gas production system. The example shows the large surges in gas and oil flow rates accompanying this phenomenon. Clearly such large transient variations could present difficulties for topsides facilities unless they are designed to accommodate them. However, designing the topsides facilities to accept these transients may dictate large and expensive slug catchers with compression systems equipped with fast responding control systems. This may not be cost-effective, and it may be more prudent to design the system to operate in a stable manner, perhaps by the incorporation of gas lift injection at the base of the riser or by the reduction of the flowline size, both of which have a stabilizing effect.

The design of stable flowline-riser systems is particularly important in deepwater fields, for example the Angolan fields Dalia, Girassol, Greater Plutonio or Kizomba, since the propensity towards severe slugging is likely to be greater and the associated surges more pronounced at greater water depths. With advances in computing power and the increasing sophistication of the transient multiphase flow simulators, engineers in the oil and gas industry have recently begun to analyze the stability of these systems using computationally intensive parametric techniques. These techniques attempt to build a detailed picture of regions of stable and unstable behavior in what is termed "parameter space."

In Figure 4, an example stability map shows a flowline-riser system, featuring regions of stable and unstable behavior. By tracing the path of the P50 production profile on this plot, it is possible to assess the likelihood of instability under normal operation. The chart shows that the system is stable under the expected production scenario through field life. Off-design cases also can be analyzed using this approach by plotting an adjusted production profile. In the case shown, the path of 50% turndown rates is indicated, which shows that system is predicted to be unstable when operated at these reduced rates.
This parametric approach to the design of stable flowline-riser systems is extremely powerful, allowing a detailed picture to be established. But one should not be deluded by the rigor of this approach since considerable uncertainty exists in a number of areas. In particular, the basic data used to build a transient multiphase flow model is subject to uncertainty as is the outturn production history and hence the actual path that will be traced on the map. Moreover, other parameters can affect the location of the stability boundary such as the producing gas-oil ratio or the installed topography of the flow line. Finally, one should never overlook the inaccuracies of the multiphase flow simulators, for accurate prediction of transients in multiphase systems remains beyond the state-of-the-art.

Taking these factors into account, a design team is confronted by another subjective decision: trading the risk of severe slugging against capital expenditure in topsides and subsea facilities.

Recommendations

It is clear from only cursory consideration that the subject of flow assurance is extremely diverse, encompassing many discrete and specialized subjects and bridging across the full gamut of engineering disciplines. Therefore, implementation of flow assurance design practices leading to successful field developments, presents a significant challenge and necessitates good communication across all aspects of the design process.

Difficulties are further compounded by the lack of objectivity that exists in the decision making process due to differing perceptions of flow assurance risk and willingness to accept this risk. Consequently, most field developments are sub-optimal and can be considered either over or under-engineered with respect to their flow assurance designs.

To address this situation, more comprehensive analysis of data from producing fields is required to evaluate the levels of conservatism in the design procedures and therefore the need for design margins. This analysis should be carried out across a wide a range of field types and should include both successful developments and those plagued by flow assurance problems. Only through such a methodical approach, will it be possible to accurately quantify the levels of flow assurance risk and reduce the levels of subjectivity evident in today's industry.
References

1. Water has a high heat capacity compared to oil, meaning that increases in the fraction of water or "water cut" yield significant increases in the operating temperatures.

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