Amir Alwazzan
McDermott Subsea Engineering
The final decision on type and level of insulation for deep and ultra deepwater requires thorough flow assurance analysis and coordination with the pipelines, risers, and subsea hardware. In addition, balancing capex, opex, level of risk, and related issues are the keys to making the final selection. The following considers non-chemical flow assurance risks management strategies.
Production companies are turning to deep and ultra deepwater prospects to replace reserves from their conventional fields. These assets often require a floating receiving/processing facility. However, some reservoirs are not large enough to justify the expense. Instead of letting such small fields lay fallow, they can be tied back to existing platforms that serve other fields. A similar approach can be considered for fields beyond peak production.
Production from remote reservoirs flows from the wellheads through jumpers, manifolds, flowlines, and risers to reach the delivery point. Flowing through these components is not problem-free. A number of factors, acting singly or in concert, can lead to hydrate, wax, asphaltene, scale, emulsion, or other flowline problems that can be severe enough to impede flow to the host facility.
Flow assurance is a structured engineering discipline that uses in-depth knowledge of fluid properties in conjunction with thermal and hydraulic analyses to develop strategies to control (prevent/mitigate/remediate) these issues and problems.
While flow assurance challenges can exist in virtually any hydrocarbon development, the deep and ultra deepwater arena and marginal fields place increased focus on the challenges. In such environments and conditions, flow assurance becomes more critical and the associated issues sometimes require different technical solutions to reach technical and economic success.
The main threats to the flowlines are hydrate formation and wax deposition. These two issues occur once the temperature of the fluid drops to certain levels. To avoid these problems, the subsea production system can be designed either to retain the heat (if the fluid is warm enough) or to add heat.
Limit seastate design of subsea thermal insulation systems (using passive techniques to retain heat) is feasible, robust, and cost effective compared to other techniques. However, some fields cannot depend solely on passive insulation to fulfill operational thermal requirements and require the use of an active heating system. Active heating systems facilitate hydrate and wax management and can be used to avoid solid depositions during both flowing and shut-down conditions. They also can be used to mitigate the plugged lines, thereby reducing and potentially eliminating, the need for chemical inhibitors injection.
It is important to note that there are other novel techniques to help eliminate or minimize flow assurance threats and risks. They include subsea separation, water injection, boosting, and compression. These are being developed on a fast pace.
Since profitability in offshore development hinges on the ability of the designers to ensure consistent and controllable flow, optimizing subsea system design to control flow assurance is a challenge.
Reservoirs change during their productive lives. Therefore, the flow assurance team should design for early-, mid- and late-life periods of development. For example, with continuous production, reservoir pressure declines, fluid composition changes with depletion, water production increases, and corrosion takes its toll. Designers must anticipate as many of these changes as possible during the original subsea and topside facilities design and then manage the rest.
Many techniques to identify, assess, and control such problems have evolved in the last two decades. To ensure fit-for-purpose flow assurance design, all available technologies, techniques, knowledge, and tools should be considered and applied where appropriate.
Identifying risks
Flow assurance and related threats and risks can be handled and controlled if they are identified in the design process.
One critical step to identify and quantify flow assurance risks is fluid sampling.
Water samples also are critical to establish flow assurance risks because of the direct relation between the produced water and issues like scaling, hydrates, corrosivity, compatibility with other water, materials metallurgy, and water handling equipment design. Without water samples, it is difficult to make accurate flow assurance risk assessments. One reason there may be no water available to sample is because the exploration well does not reach aquifer zones. In this event, it is common to consider water samples from nearby fields. However, this may give a high level of uncertainty to the flow assurance mitigation strategies.
To assess the potential of hydrates and wax problems, it is essential to conduct lab tests and analyses on the fluid samples for physical and chemical properties. In addition to the pressure-temperature phase diagram of the reservoir fluid, the hydrate dissociation curve is probably the most important information related to hydrate formation prediction.
To predict the potential of wax problems, information needed may include the wax formation phase diagram, wax composition, wax content (has no direct use in the production system design), wax appearance temperature (WAT), and pour point (PP).
Management strategies
No single flow assurance solution is best in every case. The main task of the flow assurance team is to find the optimum solution. This might be a combination of flow assurance management and remediation techniques.
In general, flow assurance risks can be managed through robust system design, appropriate operations, or a specific combination of both.
Robust system design – such as heavy thermal insulation, high-grade materials, and sophisticated mitigation systems – drives up capex. Operations such as extensive chemical inhibition, pigging, coiled tubing, and flow monitoring increases the opex as these operations require equipment and downtime. They also amplify environmental and safety concerns due primarily to the inaccessibility of the flowline. The economics and system uptime are the key parameters to balance capex and opex.
Effective preservation of fluid heat (or alternately the addition of heat) is one of the most challenging issues for subsea systems. Fulfilling this requirement may bring a range of options and techniques, both passive and active, into consideration.
Thermal management strategy is chosen depending on the level of insulation (U-value), cool-down time, temperature range, and water depth. Protecting an entire production system may require a combination of techniques.
More (and probably better) solutions to flow assurance challenges are being developed and implemented at a fast pace. Atop that list are subsea compression, boosting, water injection, and separation. These techniques can provide advantages for subsea and topside facilities design and operation. However, cost (both capex and opex), reliability, and installation remain as issues to be considered before making decisions to implement these techniques.
For a particular development, passive methods usually are considered initially to verify their performance and feasibility.
Flow assurance design procedure
In each subsea project, flow assurance parameters go into the overall field development plan as one factor in determining the feasibility of the project. Once the feasibility screen is determined to be favorable, the technical team moves to select the development concept. This requires an evaluation of flow assurance options from both a cost and risk perspective.
Upon finalizing the development concept, deciding on a suitable flowline size and the availability of reliable data, the flow assurance team starts the traditional approach of system selection. This combines sampling, laboratory analyses, and predictive modeling, and is a one-way process.
Once the possibility of hydrate and wax problems is confirmed, the flow assurance team takes a further step toward investigating different techniques for prevention. It is always the case that “a gallon of prevention is worth a barrel of cure.” Failure to design an effective system to control hydrate and wax issues could lead to plugging the lines and subsequent production loss or even field abandonment.
At this stage, the question is what type and level of insulation should be selected. The answer is subjective insofar as it depends very much on the operator’s risk exposure comfort level. In other words, operators’ strategies vary from overly conservative such as applying heavy thermal insulation to “Do Nothing”, i.e. taking no action to protect a subsea production system during shutdown.
Furthermore, there are factors beyond flow assurance to consider. These include mechanical design, installation, lifecycle, and risk. The willingness to accept risk varies with the economics of a project. Marginal projects often accept a higher level of risk if project economics dictate that no more money is available.
Often this detailed investigation takes place during front-end engineering design (FEED) of the production system, when the flow assurance team conducts more in-depth analyses for potential problems, including thermal insulation, and develops operating strategies. In this phase of a project, the flow assurance team carries out the studies to help project management with the “make” or “break” decision.
Thermal insulation evaluation and selection
Identification of insulation methods that meet technical, economical, and environmental requirements is a principle task for deepwater field developments.
Each subsea development is unique in its reservoir characteristics, fluid properties, concept, tieback length, bathymetry, environmental and operating conditions, and strategies. This causes the effectiveness of each insulation technique to vary from one development to another.
While subsea insulated flowlines can eliminate or reduce the risk of hydrates and wax deposition during steady-state production, they also must provide cool-down time during an emergency shutdown before hydrates form. In other words, insulation has to be tested for both steady-state operation and for transient shutdown.
In steady-state flowing conditions for a subsea system with short to moderate length (3 ~ 16 mi or 5 ~ 25 km) in deepwater (~6,500 ft or 1,981 m), most heat loss is in the riser. This is due mainly to the potential energy loss and not a loss to the environment. Environmental losses contribute to ~10% of total heat loss. Flowline and riser insulation only saves losses to the environment. It is also important to note that a system designed for a certain flow rate may fail for a lower flow rate and/or if the composition changes as there may be less heat input and lower thermal mass to the system which may not maintain sufficient temperatures.
For ultra deepwater environments, the transient behavior of the subsea production system is increasingly important and often dictates the subsea system design. This is because cool-down rates, and consequently hydrate formation and wax gelling times, are influenced by the insulation properties and also the topography of the flowline. Systems have been designed with cool-down times ranging from 6 to 24 hours.
In addition to insulation, thermal mass plays a role in cool-down time. The greater the thermal mass, the longer the cool down.
Thermal insulation of the flowline should be as efficient as possible to minimize heat loss in the line to counter the loss in the riser and to give as long a cool down as possible.
There are a number of flowline and riser insulation options. The selection impacts subsea system capex. Loading the flowline for maximum insulation is less expensive than loading the riser.
Deepwater insulation options are wet insulated flowline/riser, insulated flexible flowline/riser, burial, pipe-in-pipe (PiP) flowline/SCR riser, bundle flowline, thin film insulation, and hybrid riser tower. Combinations may be needed.
More active techniques also are available for heat retention/addition to the flowlines. These are vacuum systems (also applicable to heat retention in the wellbore), electrical heating, and hot water/oil circulation.
The level of protection provided by insulation depends on minimum production flow rates, reservoir temperature, tieback length, and the insulation system.
The typical approach to insulation selection is to start with the least expensive and more reliable one. Thus, from a cost and reliability point of view, passive solutions may yield better results as they cost less and need less maintenance in general. This means the first options to consider in dealing with flow assurance insulation design will be external insulation (wet insulation), burial, PiP, or flexible pipe options.
Passive insulation techniques
Wet insulation
Wet flowline insulation materials either do not need an exterior steel barrier to prevent water ingress or the water ingress is negligible and does not degrade the insulation properties. The most common types are polyurethane, syntactic polyurethane, polypropylene, syntactic polypropylene, syntactic phenolic, syntactic epoxy, syntactic epoxy with mini spheres, and multi-layered.
Polyurethane and polypropylene have been used in a range of deepwater applications. Syntactic versions use plastic or glass matrix to improve insulation properties and give greater depth capacities. Insulation composed of a mix of the two materials also has been used.
Results of high-level, steady-state analysis of passive heat retention techniques.
Wet insulation must withstand the hydrostatic pressure in deepwater. Concerns other than compressive strength include water ingress, thermal aging, and creep. Because of their relatively high density, these materials are limited to a higher range of overall heat transfer coefficients.
These materials generally are buoyant. To design an effective thermal insulation system using wet insulation, both thermal and structural issues must be considered to achieve a balance as they can conflict. For long-distance tiebacks, the need for a substantial thickness of insulation impacts the installation method due to the increase in pipe outside diameter and the field pipe jointing process. Most insulation systems are buoyant so the submerged weight of the pipe decreases. It may be necessary to increase pipe wall thickness to achieve a suitable submerged weight for installation and on-bottom stability.
For risers, insulation impacts fatigue, which is often the greatest design consideration for deepwater risers. Flow assurance engineers must work closely with the pipeline, riser, subsea, and other engineers to select the optimal type and level of wet insulation.
Flowline burial
Flowline burial began in shallow water as mechanical protection for the flowline.
The need for flowlines to be trenched or lowered below the natural seabed is based on regulations, high seabed velocity currents, and/or to improve thermal performance.
In the Gulf of Mexico, all flowlines in water depths of less than 200 ft (61 m) are to be buried with a 3-ft (1-m) cover of backfill. All flowlines/pipelines that approach shore are buried due to both regulations and the fact that the seabed current velocity is high in shallow water. It would be uneconomical to use concrete weight coating for stability during a 100-year storm.
Assuming the entire flowline is buried (either deliberately or naturally), this improves flowline thermal performance by lowering the overall heat transfer coefficient of the system and by adding thermal mass to it (increases heat retention). The insulating properties of the soil are affected by the undisturbed parent soil and the backfill efficiency. Subsea soil thermal conductivity vary between 0.33 Btu/hr.ft.°F. to 1.32 Btu/hr.ft.°F. This is high compared to other insulation. A consistent soil backfill that completely covers the flowline improves thermal insulation performance.
Also, it is important to make sure additional weight is provided to the flowline in order to get the specific gravity needed to prevent the flowline from resurfacing after burial. The additional weight can be in the form of external weight (concrete).
While not as effective as PiP in achieving low U-values, burial may be cost effective in limited water depths. However, burying coated flowlines could generate thermal properties similar to those generated by PiP systems. Two concerns arise with flowline burial, namely warm-up times from a cold start-up and flowline upheaval buckling.
Pipe-in-Pipe (PiP)
This also is referred to as “dry insulation.” In PiP, an outer barrier prevents water ingress. These systems can use a range of insulation materials. Low density materials like polyurethane foam, poly-isocyanurate foam, extruded polystyrene, fiberglass, mineral wool, alumina silicate microspheres, and translucent gel (micro-porous silica) are most commonly used.
Based on the specific configuration of the PiP system, the manufacture of it consists of either foaming the annulus after placing the carrier pipe (inner) concentrically in the casing pipe (outer) using spacers, or attaching the insulation with permanent snaps on the carrier pipe then inserting the inner pipe with insulation into the outer pipe.
Installation of PiP is thoroughly field tested. The difficulty associated with installing PiP is the water-tight bulkheads to protect the majority of the insulation material in the event of a leak in the carrier pipe. The limitation of laying PiP in deepwater primarily is the weight.
Flexible pipe
Flexible flowlines are a composite structure with a core of helically wound steel, and extruded plastic layers and insulation added in the form of flexible wrapped syntactic insulation.
For deepwater, the flexible pipes are used mainly for dynamic risers from a subsea pipeline end manifold (PLEM) or riser tower to a floating production system such as an FPSO, FSO, or TLP. Other uses are static risers, static flowlines, subsea jumpers, and expansion joints. Flexible pipes also can be used as flowlines.
Flexible pipes are used for a variety of offshore oil and gas applications including production, gas lift, gas injection, water injection, and various ancillary lines including potable water and liquid chemical lines.
One insulation material applied to flexible pipes is thermoplastic syntactic polypropylene foam, in the form of multilayer tapes. This is applied to the pipe by spiraling around the flexible pipe core, applied in between the steel tensile armor layer and the thermoplastic outer sheath. The tape is manufactured by extruding polypropylene thermoplastic material with hollow glass microspheres. Wet insulation also can be applied on the outer sheath for higher thermal performance.
Bundle systems and VIP
These technologies are forms of PiP. Bundles are used to install a combination of flowlines inside an outer jacket or carrier pipe. Bundles offer attractive solutions to a range of flow assurance issues by providing cost-effective thermal insulation and the capacity to circulate heating medium. Bundling the pipes, moreover, can simplify the subsea field layout compared to conventional steel catenary risers.
VIP (vacuum insulated pipe) is essentially PiP design with a vacuum in the annulus. The annular space between the inner and outer pipe is evacuated at the factory to a vacuum level in the 0.2 – 0.06 psi range. This minimizes the conductive and convective heat transfer into the fluid being transferred. These systems are designed specifically for cryogenic applications such as LNG transfer systems and probably are the most thermally efficient solution by far for transferring liquids at cryogenic temperatures. They could yield a U-value as low as 0.05 Btu/hr.ft.°F. The same principle works in the tubing section (VIT or vacuum insulated tubing) for several projects. VIT has been demonstrated to be a technical success as a passive thermal solution to paraffin deposition in the tubing.
Thin-film insulation
This is another novel technology being developed and implemented. It is a liquid epoxy coating, which can be applied in multiple and very thin layers to the outside of the pipe. The multiple layers may only add about 0.25 in. to the outer diameter. The conductivity of the thin films could be as low as 0.04 Btu/hr.ft.°F. but the heat capacity is not sufficient enough to provide reliable cool-down time.
Comparison study
A high-level, steady-state sensitivity analysis has been conducted by Mentor on a gas-condensate production system to investigate the thermal performance of three passive techniques: wet insulation, pipe burial, and PiP. Average values of the physical properties of the materials listed in the poster (Ed Note: See the poster elsewhere in this issue of Offshore.) are considered in this study. The production system consists of an 18-mi (29 km) tieback with a single SCR to the host facility.
The results of this study show that for this production system and based on the parameters used, the thermal performance of 1.5 in. (3.8 cm) of wet insulation is almost equivalent to burying the flowline. The results show that PiP can protect the system from wax deposition as it keeps the fluid temperature higher than the WAT to the delivery point.
Active heating
If passive techniques cannot do the job, flow assurance turns to more active solutions. Actively heated systems generally use electricity or hot fluid to heat the flowlines instead of retaining heat. However, a combination with thermal insulation can minimize power requirements. These techniques have been applied to flowlines and risers to maintain the flow free of hydrate and wax problems and to melt plugs if they occur.
With active heating, concerns such as water cut increase, start up, operating flow rate changes, and depressurization time are less important. Also, with these techniques, management of hydrate formation and wax deposition is a function of power provided, insulation applied, and transient operation time. Applications of active heating to subsea trees, jumpers and manifolds are not known.
Electrical heating
This technology is rapidly maturing and includes both direct and indirect heating techniques. It has been used since the 1970s and has found wide application in recent years.
Direct heating applies a large electrical current along the flowline, which works as an electrical conductor. Owing to the electrical resistance of the pipe, electrical power is dissipated within the flowline wall causing direct heating. The four main types of direct heating systems are PiP, fully insulated single pipe (closed system), earthed current single pipe (open system), and direct heating of the pipe bundle.
Indirect heating uses an electrical element on the outer surface of the flowline. The flowline is heated through thermal conduction between the heating element and the pipe wall. The two main types of indirect heating are induction heating and trace heating (mainly for onshore applications).
Hot water/oil circulation
Circulation of hot fluid in a pipe bundle yields almost the same advantages of electrical heating. Electrical power heats a fluid flowing in the bundles instead of heating the flowline. The heat transfers to the produced fluid. Inhibited water and oil have been used to provide heat. Using hot oil is a common technique to keep the flowlines and risers warm during shut down and to restart cold production systems. To be sufficiently efficient, it is necessary to inject a large amount of fluid to flow at a relatively high temperature.
Subsea systems are complex. As such, it is recommended to conduct risk analysis for each option. This is a systematic approach to the analysis of what can go wrong in the subsea production system. The typical approach is to define the normal operating conditions and then raise all relevant WH questions: What accidental events can occur in the system? How frequently would each event occur? What are the consequences of each event? What are the total risks of the system? What is the significance of the calculated risk levels?
About the author
Amir Alwazzan, PhD, is flow assurance team leader of McDermott Subsea Engineering, Houston, Texas.
Hydrate formation and wax deposition
Understanding the mechanisms of hydrate formation and wax deposition helps in the design of appropriate prevention, mitigation, and remediation strategies.
Hydrates are a mixture of water and gas molecules that crystallize to form a solid “ice plug” under certain conditions of temperature and pressure.
Hydrates form in two fundamental ways: slow cooling of a fluid, as in a pipeline, or rapid cooling, as with depressurization across a valve (JTC phenomenon). This is why hydrate formation problems occur more quickly than those related to wax. Hydrate formation will not occur if any one of the three required elements (temperature, pressure, and water) is not conducive.
Wax components are part of the hydrocarbon composition. During flow, wax crystals start to precipitate out of the solution once the fluid temperature reaches the WAT. The rule of thumb to avoid wax deposition in the production system is to maintain the fluid and the surfaces in contact with the fluid above the cloud point.
During shut down, if the crude oil (or condensate) cools below its pour point, it gels or solidifies when a sufficient amount of wax has crystallized to form a porous media entrapping the liquid oil. Then, fluids become increasingly viscous and difficult to pump.
It is clear that the flowing fluid temperature plays a prominent role in the hydrate formation, and wax deposition and maintaining warm flow helps avoiding these issues. In addition, maintaining the temperature of the flowing fluid at a certain level enhances product flow properties, increases cool-down time after shut-down, and meets other operational/process equipment requirements.
