Special Report: Ultradeepwater will require less conservative flow assurance approaches

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Flow assurance is a critical, often defining, aspect of deepwater oil and gas production that affects a production system's concept selection, design, and operating strategy.

Industry is increasing its awareness of the complexity of this effect and, over the last decade, has become better equipped with an extensive tool kit and a myriad of innovative technologies to tackle the difficulties of deepwater flow assurance.

But as the stakes get higher and the risks greater, is industry appropriately ready for the challenges of continued deepwater and ultradeepwater development?

Certainly, industry operates successfully in water depths up to 7,200 ft and implements tiebacks at distances up to 70 miles with proven flow assurance tools and strategies to ensure production and mitigate risks. The extreme nature of deep and ultradeepwater environments, however, presents challenges for viable flow assurance designs.

As a result, current flow assurance solutions, which successfully address these deepwater challenges, typically are conservative because of a multitude of uncertainties and associated risks. These concerns include:

• Uncertainties associated with current flow assurance design tools.
• Incomplete or nonexistent fluid samples and reservoir data.
• Mitigation of risk to health, safety, and environment.
• Mitigation of risk associated with maintaining large revenue streams through capital-intensive facilities.
• High intervention and remediation costs.

These concerns will become more taxing as the industry continues to extend water depths and tieback distances (Figs. 1 and 2).

The capital costs (capex) of these projects will demand less conservative solutions to justify their economics.

To increase the chances of success for these projects, the oil and gas industry must develop flow assurance strategies and procedures that decrease conservatism in deepwater flow assurance designs.

Components of this success include:

• Development of promising tools and technologies.
• Timely qualification of technologies for deployment in new deepwater and ultradeepwater projects.
• Implementation of quality fluid sampling programs.
• Early and active involvement of flow assurance engineers in all phases of project execution

Robust systems

At the highest level, flow assurance consists of designing systems that enable and maintain the flow of production fluids and therefore the revenue stream required to support the economics that are the basis for the development. Specific responsibilities of a flow assurance engineer include evaluating:

• Multiphase thermal-hydraulics to determine line sizes, flow-rate capacities and system deliverability, thermal insulation requirements, and slugging potential.
• Potential hydrate formation and options for preventing hydrate blockages (Fig. 3).
• Wax deposition within a pipeline system and subsequent strategies to manage or remove it (Fig. 4).
• Impact of other undesirable solids, such as asphaltenes, scale, and sand.
• Internal corrosion.
• Operability and operating envelopes of the system.

Flow assurance engineers must design the system and its operations to ensure a problem-free environment while also considering options to remediate blockages if they occur. While blockages are not inevitable, they are a potential reality with significant consequences.

Flow assurance encompasses the flow path from the reservoir through the production facilities to the export system. Engineers must design flow assurance strategies that avoid problems during start-up, steady-state operations, planned and unplanned shutdowns, flow-rate changes, pigging operations, cooldown, and system blowdown.

Each of these operations confronts flow assurance designers. Additionally, engineers must develop robust flow assurance designs and strategies so that systems can adapt to changes in pressures, temperatures, flow rates, water cuts, and reservoir compositions over the life of a field.

Flow assurance designs must result in a single system with flexibility to address these varying concerns. Most importantly, the system must be reliable and safe and must operate in an environmentally responsible manner.

Deepwater flow assurance is a broad discipline that is scientifically and technically complex, requiring technology and expertise in multiphase thermal-hydraulic fluid mechanics, produced fluid chemistry, reservoir behavior and fluid properties, full-field operations, and system operability. The discipline involves complex interfaces with pipeline, subsea equipment and controls, reservoir, topsides processing, and operations teams.

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Because of this broad scope, flow assurance is best approached from a systems perspective. Ideally, flow assurance involvement with a project begins with a strong fluid-sampling program during the discovery or appraisal stages and continues through concept selection, design, start-up, operations, and surveillance.

Economics, risks

Designers typically make flow assurance decisions by balancing trade-offs between low capex, higher risk solutions and higher capex, more conservative solutions. Higher risk solutions usually have an increased potential for production downtime and high operating costs (opex) in the form of costly and time-intensive intervention and remediation.

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For instance, a hydrate blockage may take weeks to remediate, impacting the revenue stream, adding operational expenses associated with remediating the blockage, and idling all or parts of a major capital investment. At $25/boe, lost or deferred revenue from a large deepwater production facility could easily exceed $3 million/day.

Because of the large capex involved, $1 billion or more for a large deepwater development, operators understandably pursue conservative designs. Importantly, this conservatism is not a result of ineffective flow assurance practices but rather a reasonable outcome of a design process that must mitigate large risks using design tools that have reasonable limitations associated with current stages of development and experience.

The industry has advanced state-of-the-art flow assurance design tools, but as with any complex science, most solutions rely on assumptions and approximations of science that, as yet, are incompletely understood.

Often, fluid samples are too few and too poor to provide well-defined fluid properties for a good design basis. Other uncertainties include the drive mechanism, expected production profiles, water cut, and well productivity.

Many in the industry feel that risk management, coupled with these uncertainties in flow assurance and reservoir data and design tools, leads to overly conservative designs.

Click here to view the Flow Assurance Design, Operating Strategies table.

As operators make more deepwater discoveries near existing deepwater facilities and as industry expands the reach of future prospects, deepwater flow assurance will become increasingly important to project economics and to the success of asset development.

For these projects, critical flow assurance issues will influence project design decisions and profitability through capex, opex, and risk management. Indeed, technology improvements will increase technical confidence, and, in many cases enable the viability of marginal deepwater projects.

Current practices

Management of multiphase flow hydraulics, hydrate formation, and wax deposition in flowlines lies at the core of deepwater flow assurance. These issues affect much of the capital expenditure within the design and represent most of a project's operational risk.

Commonly used strategies for managing hydraulic, hydrate, and wax issues in deepwater oil developments often rely on:

• Dual flowlines to enable roundtrip pigging for wax management, fluid circulation, and the flexibility to operate over a wide range of flow rates.
• Insulation to keep fluids out of the hydrate formation region and above the wax appearance temperature during normal operations and to provide sufficient cooldown time after an unplanned shutdown.
• Artificial lift used at the wells or near the riser base to help overcome the large hydrostatic head in a deepwater riser.
• Injection of a hydrate inhibitor prior to a planned shutdown and also during restart operations.
• Displacement of the flowline with non-hydrating fluids after an unplanned shutdown.
• Circulation of hot fluids to warm the system prior to production start-up.
• Depressurization or blowdown of the system after an unplanned shutdown to lower system pressure below the hydrate formation envelope.

Deepwater gas and gas condensate systems often rely on:

• A single flowline to tie production back to the host. Dual lines may be used if pigging is required to manage wax or liquid content in the lines.
• Continuous injection of hydrate inhibitor to protect fluids during normal operations and against worst-case conditions expected during shut-in and restart.
• Uninsulated flowlines because insulation offers little benefit for cooldown time and maintenance of fluid temperatures. This condition is a result of the low heat capacity of gas and the potential that Joule-Thomson cooling will depress flowing temperatures below seawater temperature.
• Depressurization or blowdown of the system soon after any interruption in hydrate injection to lower the system pressure below the hydrate formation envelope.

Table 1 lists flow assurance strategies of four recent deepwater developments.

For gas and oil systems with high water cuts, continuous injection of hydrate inhibitor during steady-state operations may not be desired because of the large injection volumes required and the high associated opex.

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In these situations, some operators have begun to use low-dose hydrate inhibitors (LDHIs) such as kinetic hydrate inhibitors (KHI) and anti-agglomerants (AA) instead of thermodynamic inhibitors for effective hydrate management.

The most common approach for remediating a hydrate blockage in an oil or gas system is to depressurize the system on both sides of the plug, thus allowing it to slowly dissociate. This approach, however, is not always possible for oil systems because of the hydrostatic liquid head in some systems.

In these situations, more challenging remediation options may include use of coiled tubing to deliver chemicals, mechanical removal of the blockage or localized heating of the flowline at the blockage point.

Increasing demands

Continued deepwater and ultradeepwater discoveries will place an increased demand on flow assurance and necessitate improvements to both current and emerging technologies.

Low ambient seawater temperatures, about 40° F., are well below the hydrate formation and wax precipitation temperatures. Reservoir energy is often insufficient to deliver fluids over great tieback distances and to overcome the large hydrostatic head present in deepwater risers.

Many deepwater reservoirs are at a relatively shallow formation depth that often leads to low wellhead temperatures. In gas or high GOR oil systems, Joule-Thomson cooling due to gas expansion in long risers also is a concern.

High intervention, maintenance, and remediation costs that often accompany these developments exacerbate these issues.

Further, operators continuously try to go into deeper water while decreasing project execution time and targeting the lowest project costs practical.

They implement fast-track projects that decrease the time from discovery to first oil or gas to begin earning earlier a return on the substantial capital investments. These compressed schedules leave engineers with less time to design and qualify the more complex flow assurance required for deeper water and longer tieback distances.

As flow assurance technology improves, deepwater solutions will aim to increase system reliability; decrease the amount of subsea equipment; improve intervention and remediation techniques; and decrease capex and opex—all while increasing confidence and decreasing conservatism in the designs.

A potential stretch goal may find industry developing a scheme that includes a single uninsulated flowline from a subsea well or manifold tied back 100 miles or more directly to shore or a host platform.

To achieve this vision and other stretch goals, near-term deepwater flow assurance solutions likely will involve not less but more subsea equipment for operations such as subsea separation and multiphase pumping.

Industry, therefore, needs more reliability and performance for current hardware while creating improved understanding of fluid chemistry and flow assurance design tools to deliver less complex and conservative systems. These systems should incorporate noncomplex, flexible operating procedures.

Emerging technologies

Deep and ultradeep water developments and longer tieback distances will continue to demand lower cost, more reliable technologies to manage flow assurance issues.

While many current and emerging technologies can be enhanced or better understood, necessity also will identify new enabling technologies or even technologies from other industries that can be developed further and readily applied. Table 2 lists some of the emerging technologies.

The industry, therefore, must proactively encourage the development of enhanced technologies to close technology gaps and enable decreased conservatism in deepwater flow assurance designs.

Emerging technologies with the potential to improve flow assurance include cold-slurry transport, LDHIs, heated pipelines, subsea and downhole processing, and vacuum-insulated tubing (VIT) and piping (VIP).

Cold-slurry transport in oil systems may allow wax or hydrates to form but not agglomerate or deposit to form blockages. The slurry can then be carried along the flowline to receiving facilities. If practical, this approach may allow solutions of single, uninsulated long-distance flowlines.

LDHIs, in the form of AAs and KHIs, currently provide operators with an enhancement or lower-cost alternative to injecting methanol or glycol. Improved subcooling performance for LDHIs will allow the inhibitors to be applied to more deepwater projects where ambient water temperatures can be 30° F. or more below the hydrate temperature.

Also necessary is a better understanding of hydrate formation and agglomeration tendencies, especially in black oil systems where opportunities to optimize or eliminate inhibitor injection may exist.

Engineers typically tailor chemicals to inhibit wax deposition to specific fluids, with the level of performance of a particular chemical usually not known until it is applied on the field of interest. However, this knowledge often comes too late to save insulation costs.

VIT and VIP may drastically improve the thermal performance of wells and flowlines, respectively. These technologies can greatly lower the overall heat transfer coefficients than possible with conventional insulation, thus increasing average fluid temperatures along the flow path.

Development of thin-film insulation may improve more conventional insulation systems, thus decreasing flowline costs and enabling installation of less bulky lines. So-called phase-change materials, which maintain a constant temperature as they solidify, have the potential to improve thermal management by increasing thermal hold times of flowlines while they are shut in.

Opportunities to improve project economics may exist in the study and optimization of deepwater riser insulation requirements. Potential enhancements also may exist regarding the design and thermal modeling of field joints in pipe-in-pipe and bundled flowline systems.

Finally, several flowline heating technologies are maturing and gaining operating experience. This may allow significant gains in thermal management and blockage remediation strategies. Active flowline heating is one option for enabling long-distance oil tiebacks when insulation is not practical.

State-of-the-art tools for multiphase flow simulation are impressive; however, industry continues to improve the performance of steady-state and transient multiphase flow tools, as well as tools for understanding fluid properties and behavior.

Industry also is gaining experience with multiphase flow simulators to model system performance during operations and to make real-time predictions based on system measurements. These systems can enhance flow assurance and system operability, for example, by identifying the onset of water breakthrough and predicting the approach of large liquid slugs.

Other technologies receiving much attention are subsea and downhole processing, with a few systems deployed to date. Continued advances in the performance and reliability of subsea processing components, such as separation and pressure boosting, may impact significantly the future of deepwater flow assurance.

Of course, designs of current flow assurance tools and associated technologies aim to avoid process upsets and blockages. Nonetheless, practical deepwater subsea designs must anticipate difficulties and provide for reliable remediation methods to remove blockages.

Several new and emerging remediation and intervention technologies that may enhance flow assurance capabilities include:

• Improving techniques for locating blockages.
• Enhancing mechanical methods such as using coiled tubing to drill or jet out blockages and deliver thermodynamic hydrate inhibitor.
• Extending coiled tubing reach with flowline tractors, for example.
• Determining other ways to deliver chemicals wherever and whenever they are needed in the flow path.
• Delivering controlled exothermic chemical reactions to melt wax constrictions in the flow path.

Going deeper

Joint industry projects are one way that operating and engineering companies and suppliers can manage financial exposure and risk while developing specific technologies and the expertise to support the technology.

Studies to improve predictive tools are also important, as are improved remediation and intervention strategies. Employing new technologies as a redundant back-up to a proven technology is one way to gain confidence in technology while managing risk.

Continue to qualify emerging technology to ensure that appropriate technologies are available and ready for deployment.

Promising technologies that are not qualified or that have an insufficient performance track record will not be deployed. The very nature of the current deepwater trend requires that industry constantly push the envelope, stepping out into more extreme water depths and tieback distances.

For application of new technology on fast-track projects, a growing trend, three options for qualification are at hand: invest in technology qualification before it is needed, rely on product specifications, or extend the project schedule to qualify the equipment.

Proactive qualification studies and field tests will help increase confidence in emerging technologies and ready them for the call of deepwater.

The industry should make fluid sampling a strong priority during the discovery and appraisal stages of a project. Simply stated, if fluid sampling is not done well, the uncertainty regarding fluid data will increase project costs.

Flow assurance design requires an accurate definition of the reservoir fluids. Doubts about the process fluids will increase spending on conservative designs to handle potential variances in the fluid behavior. Investment in a good fluid-sampling program, however, likely will yield great dividends over the life of a project through lower capex and opex.

The industry also should increase emphasis on early involvement of flow assurance personnel in all phases of project execution. Flow assurance and operability considerations affect an entire development over the life of a field, underscoring the critical nature of interfaces between flow assurance, operations planning and the entire project design team.

Importantly, flow assurance personnel should participate in concept selection and early project design decisions to ensure project economics are based on designs and field architectures that reflect viable flow assurance strategies and allow reliable, long-term system operability.

Further, because of the many interfaces required of flow assurance engineers, these individuals are often qualified to act in a systems capacity to help ensure that all interfaces are smooth and present during all project phases.

While oil companies are operating successfully in deepwater with proven flow assurance techniques to ensure production and mitigate risk, industry must resist the temptation to become complacent. Deeper water is on the horizon and will require better tools than exist today.

Whether economic conditions are favorable or tentative, project economic hurdle rates high or low, it is important to continue progressing the flow assurance issues and tools that will be required as more deepwater and ultradeepwater projects go forward.

The author
Scott A. Bufton is a supervising engineering specialist with INTEC Engineering. His responsibilities include project management, systems engineering, and performing flow assurance analyses. Prior to INTEC, he worked for ExxonMobil Corp. Bufton holds a BS, an MS, and PhD in mechanical engineering from the University of Illinois at Urbana-Champaign.