Copyright 2006, Offshore Technology Conference This paper was prepared for presentation at the 2006 Offshore Technology Conference held in Houston, Texas, U.S.A., 1–4 May 2006. This paper was selected for presentation by an OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Papers presented at OTC are subject to publication review by Sponsor Society Committees of the Offshore Technology Conference. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, OTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract This paper is the keynote address for the OTC Special Sessions on flow assurance. Major hydrocarbon resources are now being developed in greater water depths. There are still compelling arguments for wet tree development. Subsea technology continues to be challenged to perform beyond that which has been proven. Though greater confidence in some areas of flow assurance technology is needed, there is a greater need to understand where future development costs may be reduced. To achieve this it is necessary to assess risks more precisely so that investment costs may be minimized. To meet this objective requires willingness to take on pilot studies, and effective knowledge sharing among operators. The intent of this paper is to provide the continuing1 context for the remaining papers of this day’s sessions. It is a general statement of the author’s position on flow assurance technology and is intended to help stimulate debate. Introduction Flow Assurance addresses the petroleum extraction process from the reservoir sandface to surface process facilities and beyond.

Issues in this focus area include key aspects of fluid mechanics, heat transfer, oil field chemistry, and process instrumentation and control. It is important that we can predict fluid pressure and temperature as a function of reservoir behavior over field life, the performance of energy boosting methods and means of reducing pressure and temperature losses. We need to manage corrosion, erosion, wax deposition, scale deposition, and hydrate formation. The effect of unsteady flow on the stability of process controls and equipment continues to limit the operating range of subsea systems.

These flow assurance issues require the application of multiple disciplines, in particular a combination of production chemistry, multiphase hydrodynamics, thermodynamics and materials science. Add to that the need to have a strong understanding of operational constraints, and it becomes clear why expertise in flow assurance remains highly valued by the industry. Are We There Yet?

Expansion to harsher environments has stimulated research and field validation. Multiphase flow technology had to develop rapidly to support system design in arctic, hilly terrain, and deepwater environments. Systems became more complex including S-shaped risers, free-standing risers, coil-tubing gas lift, and split-purpose subsea operations. Over the years, field trials have been conducted, and field data collected to validate predictive codes. The intent of all this was to build our confidence in capability to address multiphase flow issues in ultra deepwater developments. We have done so well in this technology in recent years that one could possibly assert that little more development is required.

In parallel, on the production chemistry front, hydrate

research continues to forage into kinetic modeling, the potential for cold flow systems, and implementation of antiagglomerant technology in the field. Good headway has been made in kinetic inhibitor development, but subcooling requirements demanded by deepwater development still cannot be met. Anti-agglomerate development is now being implemented selectively in black oil systems, and is often included in emerging hydrate management strategies.

Wax management continues to be treated in an empirical

fashion. Some headway has been made with improvements in modeling that more effectively represents field systems. Much of this results from a combination of laboratory experiment and field trials. There is still much to be learned about wax deposition and we may be faced with additional concerns should future subsea systems be built with less thermal protection in the face of potential future cold flow systems.

We are still waiting for the promised delivery of subsea

processing as a solution to our flow assurance challenges. These systems were to be developed and proven to complement the flow assurance engineer’s toolkit. Still the most challenging is water-oil separation in the well or at the deepwater wellhead, as a design alternative to reduce hydrate inhibitor usage and manage flowline and riser hydraulics.

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Flow-Assurance Field Solutions (Keynote)N.D. McMullen, BP America Inc.

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Gas/liquid separation and multiphase boosting still have the potential for addressing recovery and riser stability issues. Also, the major issue of sand separation and disposal at the wellhead remains unconquered. Each of these challenges involves a combination of process, instrumentation, control, and electrical technologies. Ultimately we believe successful development of seabed processing capability will unlock currently uneconomic reserves and maximize the value of existing infrastructure.

In the short term, we continue to face major challenges, for

example: wax deposition modeling, reservoir souring, scale management, design of systems to tolerate sand production, and understanding the interaction between multiphase flow and corrosion.

Regardless, many deepwater production systems are in operation around the world and yielding invaluable operating data. The central challenge in deepwater flow assurance is how we, as an industry, can more effectively use that data collectively to keep pushing the design envelope. Building confidence is key to being able to address risk associated with reduced-cost systems. Importance in Deepwater

Flow assurance plays a critical role both from a technical and an economic perspective. Our design problems have become greater and the cost of solving them went up.

Lower seabed temperatures – typically in the 1-4ºC range

at 1500 – 3000m depth - made the wax and hydrate problem worse. Large elevation differences across deepwater marine risers not only make evacuation of liquids for hydrate management difficult, but also intensify slugging to the point where riser operating ranges have become significantly narrowed. Low energy reservoirs in deepwater require pressure assist sooner, yet the technology for seabed processing and/or pumping is still waiting to be implemented. High costs and environmental concerns can frustrate our ability to obtain uncontaminated fluid samples. Concerns about the effect of chemical additives on downstream processing are a significant and real concern.

At the same time, insulation costs rise in deepwater, and

any form of intervention in the event of a mechanical failure becomes almost prohibitively expensive. Little headway has been made in intervention cost-reduction.

Flow assurance still has a profound effect on field

development architecture. Alongside drilling costs and reservoir complexity, it is one of the key considerations in making the decision on whether we develop with wet or dry trees. Development costs per barrel are generally lower for subsea developments compared to stand alone hubs, so it is clearly important to maximize tiebacks once hub and pipeline/tanker export infrastructure is in place. And we certainly have many more hubs available than we did five years ago.

Still Pushing the Envelope The economic viability of a deepwater subsea tieback is

driven by the cost of drilling and pipelines. Pipelines can be at least 25% or more of tieback costs. Adoption of a traditional approach to flow assurance leads to sub economic development schemes, because pipeline costs are too high.

We are starting to see alternatives to “standard” tieback

design emerge in Angola and the Gulf of Mexico. To make targets economic, single flowline options are being explored sometimes supplemented with parallel service lines. Additional risk is taken on with these designs and must be mitigated. When prospects start off as sub economic in view of rising oil price, radical rethinking on flow assurance questions can transform field architecture and hence economics.

More importantly perhaps is the operating experience that

seems to point out that we may have built too much conservatism into our systems, and therefore built sub-optimal developments. For example, there are several Gulf of Mexico oil developments that were built to prevent hydrate plugging that in fact have never plugged in any upset condition encountered. And on the other hand gas flowline2 and dry tree examples of hydrate plugging abound.

The papers to be presented today will explore where we’ve

gotten to, what we’ve had to deal with, and hopefully will stimulate us all to pursue the potential for optimal system development in the future. Taking on the Risk

Our future deepwater multiphase systems will need to work with predictable, but significantly higher levels of risk than we see today. This means working within the hydrate formation region, or below the wax appearance temperature, or inside the asphaltene deposition region, or near to or within severe slugging conditions.

The challenge is therefore not only about confidence

building, but how the technical community can keep pushing the envelope in a prudent fashion with an eye toward rapid and cheap intervention. If we can find low-cost ways to quickly remove plugs in systems, we are likely to consider designs that have a higher inherent risk of plugging. Sources of risk relate to:

• Understanding fluid properties and obtaining quality

fluid samples • Complexity of modeling fluid mechanics and heat

transfer. • Understanding and predicting plugging. • Insufficient field data.

Fluid Properties

It is absolutely essential to retrieve quality fluid samples. Elimination of drill stem testing reduces release of hydrocarbons to the environment and risks to drilling operations, but in turn adds to the challenge of obtaining

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useable samples. Most MDT samples are contaminated with drilling fluids that interfere with accurate assessment of wax deposition and hydrate inhibitor qualification. Improvement in sampling techniques, better downhole equipment, or improved laboratory procedures are needed to reduce risk associated with contaminants. An alternative here is to have an accurate assessment of the effects of contaminants on our systems of measurement.

Modeling Complexity

Complexity of design in deepwater requires mathematical models that do not exist or require specialized model construction. Complex heated bundles and specialized bundles require computational tools that may not be the best representation of physical systems – leading to potential problems in installed systems. Flow Assurance considerations tend to drive design to complexity. Greater risk tolerance may lead to simpler, cleaner designs that are more predictable and less costly. For example a computational fluid dynamics model of tree heat transfer becomes unnecessary if we eliminate the need for insulation.

Understanding and Predicting Plugging

The underlying principle of all subsea designs is driven by the mandate to not plug the system. Since prediction is a challenge, the logical approach is avoidance through design. Improved understanding of mechanisms leading to plugging may unlock new possibilities in cleaner simpler design that would appear to be taking on greater risk when compared to today’s approach. Where plugging is a certainty, rapidly deployed cheap intervention would be a valid alternative to complex and expensive design alternatives.

Field Data

In the past there has been a concerted effort to collect multiphase flow, wax deposition, and hydrate inhibitor performance data from field operations. We all recognize that future deepwater development success depends on our willingness to risk current production to obtain key performance data and operating experience for future production gain.

In the past, data has been difficult to collect. In view of

new “e-field” initiatives3 within the industry and a willingness to instrument production systems far beyond that which has been done in the past opens many new opportunities for understanding and comparing actual operations to our models.

Given the added real-time process data now available, we

need to expand our horizons and look to new, innovative ways to exploit this valuable information.

Conclusions So is this the beginning of the end when it comes to deepwater developments? Are we there yet? Many new systems are in place now around the world and operating successfully. Within the next year some of the largest if not the largest in the world will go online. We now know that many were conservatively designed, and were we to recreate them today, costs could potentially be reduced. We also now have access

to real-time data for conducting validation work. This is an enormously powerful tool, and if we work collaboratively with other operators, there is a huge opportunity for moving technology ahead rapidly. At the same time future challenges are not escalating as rapidly as in the past, at least in the environmental theater. It is unlikely that temperatures will go lower, although high pressure and high temperature challenges will be there for us in the future. We may likely find ourselves facing challenges associated with less attractive reservoirs and enhanced recovery process issues. Time will tell. References

1. Walker, D. B. L., McMullen, N. D., “The Challenges of Deepwater Flow Assurance: A BP Perspective”, paper OTC 13075 presented at OTC 2001, Houston, April 30 - May 3, 2001.

2. A.F. Harun, T.E. Krawietz, “Hydrate Remediation in a Dry-Tree Well in the Gulf of Mexico: A Lesson Learned”, paper OTC 17814 presented at OTC 2006, Houston, May 1, 2006.

3. R. Gudimetla, A. Carroll, “Gulf of Mexico Field of the Future: Subsea Flow Assurance”, paper OTC 18388 presented at OTC 2006, Houston, May 1, 2006.