Fateh D S Sihota, Mentor Subsea Technology Services Inc.
Long deepwater tiebacks create a need for high performance insulation. The needs are being met with many different techniques through passive and active systems to alleviate the possibility of solids deposition and to reduce intervention times. The future deepwater market still holds many challenges in regards to the thermal management as the industry trend of increasing the tieback distance grows.
The development of a deepwater oil and gas field can pose challenges with high pressures, reduced ambient temperatures, and the potential for long subsea tiebacks. The reservoir fluid samples, offset distance, and intervention costs also are major factors in determining field configurations. Flowline design requires understanding hydrostatic pressures, flowing wellhead (FWH) pressures, flow regimes, and system thermal behavior. The result is a subsea production system with reduced capex and opex.
Graph represents a flow assurance study of a field development scenario in the Gulf of Mexico in 6,000 ft (1,829 m) of water.
Insulating material for long subsea tiebacks conserves system heat to help alleviate solids deposition, specifically hydrate and wax formation. Steady state and transient simulations are developed to realize topsides arrival conditions and to determine the no-touch time (or cool-down time), during the early stages of engineering analysis. The material selection and level of insulation depends upon the fluid properties as a function of temperature. Deepwater long distance tiebacks are feasible only if the insulating material has the following characteristics:
- Low thermal conductivity
- Low density
- Compressive strength
- Short procurement times
- Easy installation
- Capex within budget.
Insulation options
Generally, the industry has three insulation options for adequate heat conservation: wet, pipe-in-pipe (PIP), and flowline burial. Another option is to combine insulating, trenching, and flowline burial. There are other passive insulating techniques that perform well; however, their application is limited by design constraints.
Wet insulation systems are applied directly onto the flowline. These materials typically combine solid and foam layers made of common materials such as polypropylene or polyurethane. However, these have water depth limitations.
PIP insulation is used in extreme conditions where a combination of environmental conditions, topside arrival conditions, and tieback distance make it necessary. The inner pipe has a material such as polyurethane foam (PUF) with a higher density external coating. The air gap between the outer pipe and the insulation system adds to the thermal performance.
No material has low thermal conductivity, low density, and sufficient compressive strength to resist deepwater hydrostatic forces. Foam-based polymeric materials have been modified with the addition of micro-sized hollow glass spheres along with fillers. The low thermal conductivity of air in the glass spheres coupled with the low density and low thermal conductivity of the syntactic foam combination conserves heat. These materials are known as glass syntactic foam. Glass syntactic polyurethane foam (GSPU) has been used in deepwater, and has been qualified to be used in ultra deepwater. Glass syntactic-based insulation systems do not require an outer shield to protect the insulation; sufficient support comes from a rigid binder such as epoxy. However, rigid binders are prone to cracking. Flexible binders reduce this prospect.
Deepwater flowline and riser systems are engineered to function during the entire field life. However, the potential for degradation exists from pressure on thermal performance over time and on water absorption. PIP systems are the most robust because of the carbon steel shell, which is coated with fusion bonded epoxy (FBE). However, non-jacketed wet insulation systems are exposed to the hydrostatic pressure and cold seawater, which has the potential to degrade. Water absorption lowers the u-value of the insulated flowline due to the heat capacity of water.
A degradation test is one qualification the insulation material must pass to be marketed to the industry. The program is designed to expose the product to actual field conditions, temperature, and hydrostatic pressure. The absorption of water into the insulated flowline causes a mass increase of water, which is measured. The water absorption is further increased when the wet insulation contacts hot water. Although this is not a real-life situation subsea, the limitation needs to be studied to understand material kinetics and behavior. Overall heat transfer coefficient (u-value) is improved by lowering thermal conductivity. The u-value is used as an index in rating the various insulations. Generally, the lowest u-value associated with insulation systems would be a PIP system, and, therefore, is more expensive. This method of insulation has been used moderately because of the expense in purchasing two pipes for one flowline and the installation cost resulting from system weight.
Insulation selection
The accompanying graph represents a conceptual flow assurance study of a field development scenario in the Gulf of Mexico in 6,000 ft (1,829 m) of water. The flowline is designed to move production 21 mi (34 km) to a processing facility. The fluids must arrive at the facility at 137° F (58° C) or above due to the wax appearance temperature (WAT). The FWH temperature is 180° F (82° C). A PIP insulation system appears to be the best option, as u-value of 0.2 btu/hr ft2 °F satisfies the arrival temperature criteria. A sharp drop in temperature is seen in the riser due to the heat loss to the surroundings, a change in medium, and its velocities.
Although there is a higher cost involved in a PIP insulated flowline, its thermal performance is superior for long-distance subsea tiebacks. The required u-value can be achieved with other types of insulation such as GSPU. However, the thickness could be problematic, due to its reel-ability and the actual installation process.
PIP systems have evolved with the use of a hydrophobic silica aerogel. The aerogel contains nano-sized air pockets embedded within the silica, giving the product a large, porous surface volume. The material is approximately 97% air and 3% silica. Pore size diameter is such that it is smaller than the mean free path of air; hence, gas phase conduction is limited. The aerogel has extremely low thermal conductivity, and can operate over a range of temperatures, which makes it a good candidate for deepwater. The thermal conductivity of the material is lower than that of air. Therefore, compression reduces the size of the air pockets and increases the thermal performance of the aerogel. The compressed material would perform better if exposed to the hydrostatic forces of deep and ultra deepwater.
The application of aerogel to the inner pipe of a PIP system. Photo courtesy of Cabot Corp.
The aerogel system can only be used in PIP systems as the material is procured in sheet form and wrapped around the flowline. When comparing the aerogel to traditional insulation materials, the same thermal performance can be achieved with less aerogel. Therefore, for PIP systems, the outer carrier pipe is smaller, thereby reducing capex.
Aerogel is hydrophobic, so it cannot be applied to the flowline the same way as wet insulation. If development makes it is possible to coat the aerogel, a wet insulation could become possible in conjunction with a polymeric material. Aerogel insulation systems have other unique qualities including a relatively fast procurement time with fast application. With some recent installations in the GoM this method of heat conservation is beginning to qualify itself.
The level of insulation used depends upon the safety margin required, which is a direct function of the subsea tieback length. The safety margin is a temperature difference between the operating envelope and the hydrate formation curve or the cloud point curve at a specific pressure, during steady-state conditions. The margin also could be specified as the arrival temperature greater than the hydrate formation temperature or the WAT. In this case, a reduced continuous chemical injection dosage rate or reduced pigging frequency for wax removal could be chosen. There is a trade off between the capex and opex. A subsea production system with good insulation requires less opex for chemical injection or mechanical intervention. Typically, a scenario including a combination of flowline and riser insulation plus continuous chemical injection is adopted.
Engineering analysis will determine the level and type of insulation. The main influence is offset distance. In long-distance tiebacks, heat loss to the seawater during steady-state operations determines the u-value because of the large surface area involved. During normal operations, the subsea operating envelope will show how prone the system is to solids deposition. For a comparatively shorter offset distance the amount of insulation or required u-value is based on shut-in conditions. Mitigation time can be determined once the flowline has cooled to below the hydrate formation temperature. The best insulation system then will be selected based on this analysis, the recoverable assets, and other project costs.
PIP systems have been improved by using reduced annulus pressure in conjunction with micro porous material such as low density polyurethane foam (LDPUF), with a phase change material (PCM). The reduced pressure increases thermal performance, and the phase change material stores system heat during normal operations which then releases slowly to the produced fluids during shut down. The overall effect is that the no-touch time can be extended to one week or more.
Reduced pressures in the annulus of a PIP system increases thermal performance of the flowline by reducing the effects of convection and conduction through the insulation and the annulus. Therefore, vacuum insulation is effective in providing very low u-values. Vacuum insulated tubing is used widely in the industry, but it has not yet been used in deepwater flowlines and risers. The critical factor is how long the vacuum in the annulus can be maintained, which depends on the integrity of the welding process.
Heating the subsea flowline and riser system is another viable technique. This increases project capex and opex, as dual flowline may be needed. Also, power costs increase. There are two methods of heating: indirect and direct:
Indirect heating: Hot water is circulated in a bundle flowline to warm the produced fluids
Direct heating:An electrical current is provided through the pipe or through an umbilical to heat the fluids.
