What is flow assurance

Flow assurance is the overall hydraulic ability of an oil and gas field to produce hydrocarbons efficiently thought the lifetime of the field. Issues related to flow assurance can cause huge financial losses due to production interruption or by limiting the overall recovery from the field.

For subsea fields, flow assurance is very critical because of the high pressures and low temperatures (~4 degrees Celsius) involved. As hydrocarbons flow from the reservoir to the topside process facilities the temperature decreases quickly. At the reservoir, the temperature is more than 100 C. At the seabed, the ambient temperature is around 4C and the fluid will start to cool down. Cooling down causes flow assurance problems such as Hydrate Formation and Deposition of waxes.

Mitigation of flow assurance problems is often accomplished by:

• Thermal Insulation
• Chemical injection
• Heating

As the flow (mixture of oil, gas and water) moves from the reservoir to the process facilities the pressure decreases since:

1. The well fluids move upwards in the production tubing of the well. The larger the distance from the reservoir to the sea bed the larger the pressure drop (distance a, image 1). The distance is in the order of magnitude of 2000-6000 m.
2. Local losses at inline equipement (fluid passes wellhead, X-mas tree, manifolds etc)
3. from the upward flow in the riser and into the process facilities.

In the design of the system, the pressure loss is taken into account during the hydraulic design. The input is the fluid properties, reservoir pressure, and flowline parameters. With input, we can calculate the pressure through the system and check whether the proposed production system will allow the oil to flow to the process plant and consider what should be planted for the pressure maintenance requirements,

Possible ways to boost the pressure are:

1. water or gas injection
2. well gas injection
3. downhole pumping
4. seabed pressure boosting (multiphase pumps, separation and then boosting, subsea separation and injection)
5. riser lift

Problems associated with pressure loss

The dissolved gas in the flow of oil will bubble out of the oil. Thus, the flow becomes multiphase (liquid and gas). Multiphase flow is undesirable because it is unstable and pressure boosting can only be applied with expensive and unreliable new technology such as multiphase pumps or subsea separation.

How can we maintain the pressure of the reservoir?

Reservoir pressure can be maintained over the life of the field by water or gas injection. The injection well location and depth is selected such that the optimum result is accomplished

Hydrates in Offshore Gas Pipelines

Hydrates are crystals that formed when water and gas are combined in a low temperature and high pressure environment. During production, the oil and gas that comes from the reservoir is a mixture of oil, gas, water and sand. If the pressure is high enough and the temperature low enough, water and gas are combined and form hydrates.

Hydrates are solids with a crystal form. Once formed hydrates can reduce the diameter and ultimately block the pipeline. Hydrates can plug the downhole tubing, tree and manifold piping, flowlines and risers. The plugs can be difficult to locate and remove leading to significant losses in production and revenues

We can prevent or mitigate the formation of hydrates by:
1. Chemical injection. Depending on the reservoir fluids the injection chemical can be
– Methanol or Mono Ethylene glycol (MEG) for gas and gas/condensate wells.
– Kinetic gas hydrate inhibitors for low water production rates
2. Thermal insulation. Thermal insulation of subsea infrastructure(pipelines, risers, manifolds etc) results in maintaining the temperature of the flow above the hydrate formation temperature. Thermal insulation also acts in preventing the rapid cool-down during shut downs  providing thus time for the operator to take remedial action.
3. Lower the pressure. Operating pipelines at lower pressure especially during shut-in conditions. 
4. Removal of water. It is possible to prevent the formation of hydrates by removing the water from the flow before the the fluid reaches temperature and pressure conditions that hydrates are formed.

Further Reading:

http://www.ipt.ntnu.no/~jsg/undervisning/naturgass/lysark/LysarkSandengen2010.pdf

http://www.drbratland.com/free-book-pipe-flow-2-multi-phase-flow-assurance/table-of-contents/

3. Waxes in Oil

Low temperatures result in the deposition of the desolved waxes of the oil on the internal surface of well tubing, and on the wall of flowlines and risers. As a result the diameter of the pipes is reduced and depending on the deposition rate wax may ultimately block the line  

Was deposition can be avoided by:
1. Thermal insulation or heating of the affected parts (flowlines, riser, trees etc) in order to maintain the temperature above the deposition threshold.
2. Pigging of the flowline to remove waxed that have been deposited
3. Chemical Injection: Injection of 

Futher Reading:
http://paraffindepositionandcontrol.wikispaces.com/4.+The+problem+with+Paraffin+Wax+De

4. Emulsions

Oil and water form emulsions that result in high pressure losses and reduction of production

Sands get in the produced fluids as the pass through the formation in to the well.

Sand can cause:

1. Erosion of the SPS components
2. Block of SPS
3. If enough sand is produced a big void may be formed at the bottom of the well which can lead to a collapse and total destruction of the well casing and tubing

Eliminate or mitigate sand related flow assurance problems:

1. Reduce production rate. By reducing the production rate the hydraulic gradient of the flow in the well is also reduced. As as result the sand production will reduced because the flow through the reservoir pores will not be strong enough to pull sand from the reservoir. If the production of the field need to be kept then drilling another production well should be considered

2. Pigging and flushing flowlines if sand is deposited in the flowlines

5. External Pipeline Corrosion

External pipeline corrosion is casaude by

2. Internal pipeline corrosion

2.1. General

Internal pipeline corrosion is a common problem when there is addiquate concentration of CO₂ or H₂S in the well fluids. 

The most widely used methods to prevent internal corrossion are the following:
1. Chemical injection: Inject corrosion inhibitos () in the well fluids

2. Corrosion Resistant Alloys (CRA): This is the most common sulution. Instead of using Carbon steel pipes we use stainless steel or … pipes. Compare to chemical injection the use of CRA has a higher initial cost, however there is no operational cost and the system has a high reliability

3. Corrosion allowance: providing extra wall thickness during design in order to act as a corrosion allowance in case of temporary failure in the chemical injection system
 

2.2. Corrosion Perdiction

The degree and extent of corrosion can be calculated using corrosion models such as NORSOK M-506, de Waard 1995, and IFE top-of-line corrosion. The models are cable of identifing arean along the pipeline where corrosion is likely to occur and the effects of CO2 corrosion.

2.3. Corrosion Monitoring

Q&A Pipelines

What is the effect of field age in connection with flow assurance?

1. Water-cut increases with time and thus the fromation of emultions
2. Pressure reduces and deposition is easier. However, hydrate fromation is more difficult because of the lower pressure. 
3. Boosting may be needed

What flow assurance problems are anticipated during planned or unplanned field shut-downs?

1. The fluid in the SPS starts to cool down
2. If the temperature is reduced below the hydrate formation temperature
3. Wax formation

How to prevent/mitigate flow assurance problems during planned or unplanned field shut-downs?

1. Cool down time can be desinged to be sufficient for the operator to take remedial actions such as:
   – blow-down to reduve the flowline pressure below the critical hydrate formation pressure
   – if hydrostatic head of liquids in the riser is high flowlines and risers can be pigged and displaced 
2. Thermal insulation or heating of line and riser to reduce cool-down time.

Partial Subsea Separation and Pressure Boosting

Seperation and Single Phase boosting

1. Kvaerner Booster Station (KBS partial seperation and Boosting)

2. VASP System: Baker Jardine/Mentor Engineering

Multi-phase pumping

Hydrodynamic

• Nautilus: helico-axial principle, electric, Sulzer, Framo, Total
• SMUBS: Shell, helico-axial, waterdriven hydraulic turbine

Positive Displacement

Srew Type

• Weir
• Bornemanm: two screw positive displacement
• Leistritc
• Kvaerner Eureka: Subsea multiboosting system