RISER SYSTEMS 

Artificial lift is required when the natural reservoir pressure is insufficient to lift the produced fluids to surface at economic production rates. This can occur in the event of water breakthrough at the wells (increasing the weight of the liquid column), low pressure at the reservoir or the production of low GOR heavy crude.

Artificial lift also helps to stabilise the fluid flow regime, and hence eliminate slugging in the production Riser.

Artificial lift may be a cost effective solution to develop satellite fields as it facilitates the transportation of produced fluids over longer distances, thus reducing the investment by simplifying the production layout and reducing the number of platforms. Furthermore, it increases field life and recovery rate.

The offshore oil and gas production is typically based on natural flow driven by reservoir pressure, water injection and artificial lift, whenever necessary.

The flow rate requirement on top of the production riser is formulated as follows:

Where:

Or, in the case of riser Artificial Lift:

Where:

In this formula, two terms can be adjusted to improve the flow rate:

The first method calls for electrical submersible pumping to perform the artificial lift whereas the second for gas injection.

The different artificial lift methods are listed below:

The following covers only the gas lift method (i.e. the most cost effective solution) applied to rigid or flexible riser and hybrid riser tower having the gas injection point at the riser base.

The gas lift method principle is to increase the flow rate by reducing the specific gravity of the producing fluids.

For subsea application only gas lift has been widely used as artificial lift method, due to its intrinsic similarity with onshore' s gas lift method. This similarity comes from the fact that it is driven by a power fluid using roughly the same components for both onshore and subsea application. For this reason, gas lift is today seen as the subsea conventional artificial lift method.

Sometimes, gas lift may not be the best method to fit specific field's requirements. This happens, for instance, when there are long distances between well heads and the host platform system, and the gas injected, even though helping the flow in the vertical sections (well and riser), increases pressure drops in the horizontal section of the Flowline. Additionally, this method demands compressors and an increase of gas facilities to handle the extra recycling gas, with consequent drawbacks on platform weight and space requirements, which have a high impact on offshore installation costs.

Other problems with the gas lift method are its contribution to the cooling of the producing fluid due to the gas temperature and expansion (Joule-Thomson effect) and a relatively low efficiency (i.e. a ratio between output and input hydraulic power of about 20%). The cooling of the produced fluid will aggravate the wax and hydrates formation problems.

The gas lift method hence requires to be early integrated in the riser design as a part of the riser system; this is especially true for concepts such as riser bundle or hybrid tower.

No difficulties, regarding the riser system definition, are expected when using the conventional gas lift method; the only requirement is the provision of a sufficient number of gas lift line. But an activated riser configuration requires additional studies, mainly due to the lack of experience. As the injection point is positioned on the lower part of the Riser, special studies must be conducted to precisely define the required equipment (valve, gas diffuser, etc.) and the consequences on the riser structure (reinforcement to increase high stress and fatigue resistance) and behaviour.

The gas lift method is characterised by two modes:

10.2.1   Internal gas lift using coil tubing

The artificial lift is performed by means of a coil tubing deployed from the inside of the production riser at the surface (see Figure 10.1, “Gas lift through coil tubing”). This method is well adapted to flexible and rigid riser.

The gas injection point can be selected by adjusting the length of the coil tubing. This solution requires one coil tubing per riser, which can also be used for the chemical injection.

Figure 10.1 - Gas lift through coil tubing

The advantages and disadvantages of this solution are summarized in Table 10.1, “– Advantages & disadvantages of gas lift through coil tubing”:

Table 10.1 - – Advantages & disadvantages of gas lift through coil tubing

ADVANTAGES	DISADVANTAGES
Possibility to adjust the injection point to the production type (specially during start up) No requirement for thermal insulation on gas lift lines (i.e. gas remains at effluent temperature as there is no contact with sea water) No interaction with the environment loads on the production line	Recovery of coil tubing before pigging Difficulty to study the dynamic behavior of both lines (vibration of gas lift line, potential wear by friction, requirement for centring devices, etc.) Flow section reduced by the presence of the gas lift line High cost due to coil tubing unit and deck space Not applicable to hybrid Riser

List of main equipment is provided in Table 10.2, “– Main equipment of gas lift through coil tubing”:

Table 10.2 - – Main equipment of gas lift through coil tubing

SURFACE EQUIPMENT	SUBSEA EQUIPMENT
Gas compressor Gas injection control system Coil tubing unit	Production Riser

10.2.2   Internal gas lift lines integrated to production riser

In this method the artificial lift is performed by means of gas lift lines surrounding the production riser. The bottom end terminations of the gas lift lines are connected to isolation valve (s) controlled from the surface for safety reasons (see Figure 10.2, “– Gas lift line integrated production riser”). This technique is well adapted to flexible risers (i.e. TECHNIP-FMC Integrated Pipeline Bundle see section Section 5.2, “Flexible Riser Systems”).

Figure 10.2 - – Gas lift line integrated production riser

The advantages and disadvantages of this solution are summarised in Table 10.3, “– Advantages & disadvantages of gas lift line integrated to production riser”:

Table 10.3 - – Advantages & disadvantages of gas lift line integrated to production riser

ADVANTAGES	DISADVANTAGES
Standard installation method No interference with pigging or coil tubing operations No requirement for thermal insulation on gas lift lines No interaction with the environment loads on the production line	Increase drag and VIV due to larger external diameter Increase tension load during laying operation and at hang off platform Requirement for specific tensioners Flexible technology to be qualified for deep waters including manufacturing process Technical and economic limitations to small production Risers (ID = 6"-8") High purchase cost

List of main equipment is provided in Table 10.4, “– Main equipment of gas lift line integrated production riser”:

Table 10.4 - – Main equipment of gas lift line integrated production riser

SURFACE EQUIPMENT	SUBSEA EQUIPMENT
Gas compressor Gas injection control system	Production Riser : 6 or 8 inch Gas lift lines : ½ - 3 inch Umbilical line Surface controlled isolation valve (s) Gas diffuser head

10.2.3   External gas lift line

The artificial lift of the produced fluid is made using gas lift at the riser base. The gas injection is performed from the surface to each production riser through a dedicated line.

Several solutions can be considered for the installation of the gas lift line:

• Externally mounted on each production riser using the piggy back method (see Figure 10.3, “Gas lift line in piggy back”).

• Inserted in the thermal insulation of the production riser.

• Clamped to the central member of the hybrid Riser.

This technique is applicable for all type of risers.

Figure 10.3 - Gas lift line in piggy back

The advantages and disadvantages of this solution are summarized in Table 10.5, “– Advantages & disadvantages of gas lift line in piggy back”:

Table 10.5 - – Advantages & disadvantages of gas lift line in piggy back

ADVANTAGES	DISADVANTAGES
Surface control of the gas injection No interference with pigging or coil tubing operations Applicable to most type of Risers Complete independence between production and gas lift lines Configuration well adapted to coil tubing pipe technology Low cost solution Lower operation and maintenance cost	Increase drag Longer installation time (two lines) Requirement for thermal insulation on both lines Dynamic behaviour of lines may impact on clamps (fatigue, wear, etc.) Critical injection point requiring detailed engineering

List of main equipment is provided in Table 10.6, “– Main equipment of gas lift line in piggy back”:

Table 10.6 - – Main equipment of gas lift line in piggy back

SURFACE EQUIPMENT	SUBSEA EQUIPMENT
Gas compressor Gas injection control system	Production Riser : 6 or 8 inch Gas lift lines : ½ - 3 inch Umbilical line Surface controlled isolation valve (s) Gas diffuser head

10.2.4   External common gas lift line

In this configuration, the gas injection point is also at the riser base. The gas is routed from the surface to a retrievable subsea manifold through a common gas lift line. The gas distribution is then made using hard piping or jumpers connecting the subsea manifold to the production riser (see Figure 10.4, “Manifold_based_gas” ).

Figure 10.4 - Manifold_based_gas

– Manifold based gas lift method

An alternative to the above solution consists to gather all gas lift lines together in a multi-bore line, which will be distributed at the riser base for the gas injection in the production risers.

In the first alternative, the gas injection is controlled from the surface by means of electro-hydraulic umbilical connected to the subsea manifold, whereas in the second solution, the control is done directly from the surface. This technique is applicable for all type of risers.

The advantages and disadvantages of this solution are summarised in Table 10.7, “– Advantages & disadvantages of manifold based gas lift method”:

Table 10.7 - – Advantages & disadvantages of manifold based gas lift method

ADVANTAGES	DISADVANTAGES
Limited number of lines to be installed Surface control of the gas injection No interference with pigging or coil tubing operations Applicable to all type of Risers Complete independence between production and gas lift lines Configuration well adapted to coil tubing pipe technology	Well adapted for compact Riser configuration Requirement for thermal insulation on both lines High number of subsea connections Number of production Risers limited to subsea manifold and gas lift line capacity Requirement for subsea foundation to support all subsea equipment Low flexibility in operation and maintenance High cost solution

List of main equipment is provided in Table 10.8, “– Main equipment of manifold based gas lift method”:

Table 10.8 - – Main equipment of manifold based gas lift method

SURFACE EQUIPMENT	SUBSEA EQUIPMENT
Gas compressor Gas injection control system	Production Riser : 6 or 8 inch Gas lift line: 8 or 10 inch for common line and 2 or 3 inch for multi-bore line Retrievable subsea manifold Umbilical line Choke valve (s) or isolation valve (s) Gas diffuser head (s)

10.2.5   Gas lift through Pipe in Pipe annulus

A gas lift requirement to a riser can be achieved by a solution utilizing the pipe in pipe configuration, with the annulus conveying the gas injected at the top of the riser. The gas enters the production line inner pipe at the base of the riser. The two pipes are connected together at the riser string base via a bulkhead and at the top via a hanger spool. Centralizers are located along the string to avoid contact of the two pipes during the welding of the casing. The insulation on the riser is applied on the outer pipe of the pipe in pipe section.

Conveying the gas through the annulus of a pipe in pipe externally insulated is one of the most reliable solution in terms of flow assurance.

Figure 10.5 - Pipe in pipe cross section

Gas lift injection through PiP annulus is used on following TOTAL developments : CLOV (production HRT), KAOMBO (production SHR) and EGINA (production SHR).

The advantages and disadvantages of this solution are summarised in :

Table 10.9 - – Advantages & disadvantages of pipe in pipe configuration

ADVANTAGES	DISADVANTAGES
Limited number of lines to be installed Surface control of the gas injection No interference with pigging or coil tubing operations Configuration well adapted to coil tubing pipe technology good thermal insulation annulus provides capability for active heating by circulation of hot water to allow hydrate/wax removal or increase production arrival temperature	Well adapted for compact Riser configuration Low flexibility in operation and maintenance High cost solution Heavy hanging weight for pipelay in ultra deep water. technological uncertainty and risk associated with this technology.

List of main equipment is provided in :

Table 10.10 - – Main equipment of pipe in pipe configuration

SURFACE EQUIPMENT	SUBSEA EQUIPMENT
Gas compressor Gas injection control system	Production Riser