7.1. General Description

Based on the analysis described in the previous chapters, the final choice is to have a subsea system, a purpose built FPSO and a new gas pipeline. The following paragraphs will elaborate on the general concept and its implications on the operation of the field.

7.1.1. Production

During the first five years of the field life, we will produced:

  • Oil from two horizontal wells
  • Gas from four deviated gas wells.

Oil plateau production is 30 000 bod and the plateau production for gas is 800MMscf/d for gas. Oil is stored in the FPSO and offloaded every 15 days. When oil production reduces, the oil wells will be converted to produce gas. After 7-9 years of production, three extra wells will be drilled to maintain the plateau production level. The depletion strategy was derived in Section 5.3. Depletion Strategy

The choice to produce oil in the first years of the field life has a detrimental impact on initail cash flow and huge economic benefit. In addition, it safeguards the viability of the projet as it gives a big revenue to compensate in the event of delays in the construction of the gas pipeline. As soon as the FPSO and the subsea system are in place the production of oil can start independently of the status of the pipeline. If the pipeline is not finished the gas can be flared (this is common in Vietnam for the cases were the pipeline is not ready yet) or rebinjected using the CO2 rebinjection well.

7.1.2. Vessel Type

The long field life of 28 years is the deciding factor for choosing to build a new FPSO instead of converting a tanker. The dimensions of the vessel are mainly driven by the required storage capacity for oil and the dock size of the shipyard. A small FPSO with a deadweight of 50000 b 70000 metric tonnes is chosen since the required storage is 300 000 bbl. The estimated length of the vessel is 180 m and the beam 30 m. A turret is fitted at the bow to allow the vessel to weathervane.


Providing the Vietnamese economy with a constant gas supply is extremely important. To ensure that this is the case, any production platform must be as reliable as possible. The need to move the vessel to a dry dock for repair must therefore be avoided. There are at the same time limitations to certain in-situ repairs as well. Activities that include welding and the use of hot torches are hazardou and require special attention, assessement and planning.

Two main mechanisms are to be given special attention. Fatigue can occur because of hogging and sagging. Waves that with wave length in the order of magnitude of the ships length are critical. Moreover, short waves that slam against the bow and can cause structural damage by loosening shell plates

A new built FPSO preferable over a conversion, because in this way it can be better optimized to the field conditions. This compensates for a slightly longer roll out and a higher CAPEX.

7.1.3. Location

The FPSO is located in the field close to the Drilling Center A (see chapter 4). This eliminates the need for unnecessary long subsea flow lines and flow assurance becomes less of an issue.

7.1.4. Mooring system

The vessel is moored using an internal disconnectable turret that allows the vessel to weathervane and to disconnect in the event of a typhoon. Weathervaning is necessary in order to reduce the environmental loads on the vessel from the strong and not directional currents and winds in the area. Placing the turret at the bow and closer to the turret has the advantages of easier weathervane and of increased safety since it is located far from the accommodation. The size of the turret is based on 5 risers (3 production and 1 water rebinjection and 1 CO2 reb injection) plus spare slots for possible expansion. The reduced number of risers is achieved by manifolding.

For minimizing the riser tension and vessel motions, a turret location closest to the mid ship would be optimal. However, this means that weathervaning is less effective, and would have to be aided by thrusters.

The FPSO is kept stationary by application of basic dead weight anchors. The water depth is such, that the effect of anchor weight is not detrimental to the buoyancy. Selecting a more advanced system such as suction anchors is not advantageous. The mooring lines will form three groups (Figure 22). This configuration allows for more space for other vessels and reduces the risk of a rises and umbilicals interfering with the mooring lines.

7.1.5. Topside facilities

Once the largest part of oil has been depleted, the main focus switches to the remaining gas. Oil, condensate, water, gas and other fractions like H2S and CO2, are separate. The aim is to produce gas that will not need any further processing onshore. Export takes place in a single phase pipeline to shore.

Produced water is re-injected since this solution is more cost effective and environmentally friendlier than the option of full treatment of water and discharge in the sea. Since we produce from a gas reservoir under high pressure, water re-injection does not help to support the pressure. On the other hand CO2 re-injection can enhance recovery. In case of emergency, gas flaring is possible. The flare is at the bow, as far as possible from the living quarters.

7.1.6. Offloading

The produced oil is initially stored and subsequently offloaded by shuttle tankers. The tandem stern offloading approach was selected based on the safety, cost, and reliability factors. A floating hawser, carried by a work-boat, connects the two vessels and provides a means to transfer oil or condensate in a relatively short amount of time. Also, the fact that shuttle tanker is located directly behind the FPSO, helps to eliminate the exposure of environmental forces on the shuttling tanker.

7.1.7. Transport

Connecting the field to the existing Nam Con Son 2 (NCS2) pipeline is left out mainly because the cost of building a 170 km multi-phase pipeline to connect to NCS2 is comparable to the cost of building a new single-phase pipeline to the shore. All gas process will be done offshore such that no further onshore processing is required. Also, the choice of a new pipeline has the benefit of spare capacity to serve the needs of nearby future filed developments.
Building a new single-phase pipeline has another advantage over the long run. The removal of water and gases (H2S and CO2) increases the corrosion resistance. For a field life of several decades, where the reliable transport is paramount, it safeguards a failure free operation. Three possible pipeline routes were considered before deciding on the route mentioned in section 5.4. The aim was to avoid the environmentally sensitive areas and have a route that would be short but also will raise the least objections during licensing for construction.

7.2. Drilling and Subsea

7.2.1. Wells and drilling phases

The first drilling phase includes six wells (see Table 5b1). Two of them are horizontal (combination wells, Figure 5b2) for producing initially oil and then gas. The other four wells are deviated gas production wells. The second drilling phase will take place after 6b9 year of production and three deviated wells will be drilled (see Table 5b2). A description of the wells drilled at each drilling phase along with the estimated production capacity and drainage area is shown in Fout! Verwijzingsbron niet gevonden. The two existing vertical exploration wells will be used for rebinjecting the produced CO2 and water.



7.2.2. Drilling

Error: Reference source not found shows the well layout. The first drilling phase takes place at Drilling centre A (DCA) and the second phase at drilling centre B (DCB). Deviated and horizontal wells were chosen since they have higher production; thus, the field can be developed with fewer wells and fewer subsea trees. Deviated wells also result to smaller subsea footprint for the development. Two drilling centres are used because drilling from only one location would require more drilling length to reach the extent of the reservoir.
The cost effective way to drill the wells is using a MODU (semisub or drilling ship). Batch drilling will be applied. All identical well sections at a drilling centre will be drilled in turn rather than drilling individually each well (i.e. all the identical well sections will be drilled before progressing to the smaller diameter section). This results in fewer rig moves, faster drilling, lower emissions and a lower environmental impact compared to conventional sequential drilling. The drilling of one well is estimated to take about 50 days.

7.2.3. Subsea

Subsea facilities comprise of:

  • 2 manifolds (one at each drilling centre)
  • A 5 km, integrated flowline bundle that connects the manifold of DCB with the riser base
  • 9 subsea production trees connected to their manifolds via jumpers
  • One subsea produced water re-injection tree (existing well)
  • One subsea produced CO2 re-injection tree (existing well)
  • Riser base, with 3-5 flexible production risers, a water injection riser and a CO2 injection riser
  • Umbilicals and control systems

The protection of the subsea equipment that are near drilling center A is deemed not necessary since all equipment is very near to the FPSO and the interference with fishing or navigation is very unlike. Subsea equipment near drilling center B will be protected.

7.2.4. Xmas-trees

Horizontal trees are used because they allow drilling and workover to take place without removing the tree. Chemical injection for flow assurance and maintenance is also possible.

7.2.5. Subsea manifolds

Two cluster manifolds are used to commingle the flow from the subsea wells. The distance from the manifold to the wells is 10 to 40 meters. The manifold at DCA will have tie-in slots for nine wells. Six slots for the wells of the first drilling phase and three spare slots. The manifold at DCB will have tie-in slots for five wells, three for the wells of the second drilling phase and two spare slots. The spare slots can be used if it is need to produce faster or if the high SfR is realised.

Subsea metering is employed in the manifolds for metering flow from the wells. The restriction of metering at the manifold is that only one well is measured at a time, but this is sufficient since the number of wells is small. The manifold will accommodate two umbilicas for controlling the wells and injecting chemicals. The manifold will be founded on a suction can or foundation piles depending on the soil conditions. From the manifold, the flow is direct to the riser base using three 16 inch flowlines. 

7.2.6. Injection of the produced water and CO2

The extracted water and CO2 from the processing at the FPSO is re-injected to the vertical wells using two flowlines that connect the riser base to injection wells.

7.2.7. Riser base and risers

The flowlines from the manifold are connected to the risers through the riser base. Then the flow is transferred to the FPSO using three production risers. Two additional risers are required for the injection of the produced water and CO2. The dynamic flexible risers and the dynamic control umbilicals are approximately 600-700 m in length and will connect the turret of the FPSO to the subsea facilities on the seabed. The FPSO will be moored at a suitable position slightly offset above the midpoint of the bundle, near DCA.

7.3. Process facilities

Process facilities

Separation, treatment and production will take place aboard an FPSO vessel. Produced hydrocarbons will be lifted to the FPSO vessel via a flexible riser, where the multiphase flow, coming from the field, will be separated and processed on the topside.

Processing plant

The main functions of the process plant used to produce are:
Separation oil, condensate, CO2, gas, water
Stabilized condensate storage
Gas handling – compressor, dehydration
Injection of CO2 and chemicals
Evacuation of gas, condensate
The gas and condensate processing unit is illustrated in Figure XXXXX.

Figure XXXX: Gas and condensate processing unit

Incoming raw gas

Incoming raw gas, condensation and water will be separated on deck and after this processed to make a pipeline able product. After the separation the gas will be compressed. The condensates will be after processing evacuated to shore as well. The acid gas CO2 will also be separated from the gas and re‐injected into the ground.


The condensate/oil processing will be contrived from running the produced hydrocarbons through a three stage separation process, afterwards dehydration and desalting of the separated condensate/oil. After separation, the produced oil can be stored on board of the vessel, which will be able to hold 300,000 barrels of oil, making for 15 days of storage at maximum vessel production capacity.
Next to gas and condensates, water will be produced, separated and after cleaning it carefully, dumped overboard.
Later in the field life this water can be used for water injection.


The separated gas will also be treated on board of the FPSO vessel. Dehydration will take place via glycol treatment (TEG) and dew point control will be executed via refrigeration of the gas. Even though the projected gas productions only range up to 18 MMscm/d, the FPSO will be designed to cope with production rates up to 22MMscm/d. The overdesigning of the FPSO (by roughly 20%) is done in order to deal with uncertainties of the field production levels. Any unnecessary loss of productivity should, naturally, be avoided at all time.


Vietnam has signed the Kyoto Protocol. The intent of this Protocol is: ‘stabilization of greenhouse gas (CO2, CH4, N2O, SF6, HFCs and PFCs) concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system’.
The CO2 content of the gas in the Bi anphianam Field has an average of 5%. With a total amount of 6.5 Tscf of natural gas being produced, a volume of 325 MMscf of CO2 will be produced during the development of Bi anphianam Field.
This field will probably need water‐ or gas‐injection to maintain a high enough pressure for two reasons:
• To prevent condensate blocking
• To keep the project profitable because the production is high enough.
Of course several extra processing units should be located on the topside.
These processing units separate the CO2 from the gas and pressurize it to allow it to flow to the gas‐injection wells. For the separation, membrane skids will be used. A typical example of such a membrane skid is shown in Figure 6.3. Membrane technology can be seen as a promising, upcoming technology for effective CO2 removal from natural gas.
Like almost every floating production platform, this FPSO has a flare structure for flaring excess gas. The power unit on the platform provides electric and hydraulic power. In cause of mergency or maintenance an extra generator provides the necessary power to control all the processes.

7.4. Transport

Oil offloading

Oil is stored in the tanks and offloaded in shuttle tankers at regular interval during the first years when oil production is high. Later in the field life offloading will be done every few months. The tandem-stern offloading approach was selected based on the safety, cost, and reliability factors. A floating hose, carried by a workboat, connects the two vessels and oil is pumped to the shuttle tanker.

Gas Export

Gas export will take place via a 300 km single-phase pipeline to shore. The route of the pipeline is shown in figure 2. Two routes where considered (dashed lines). The aim was to avoid passing through the protected area. Finally, we chose route A since it is the shortest. In order to reduce the possible public objection on the route we decided to gross the protected coral reef by following the same route that NCS1 and NCS2 pipelines. In this way the environmental monitor, require before getting the approval to construct the pipeline will be much less since the area has been investigated previously and there are environmental impact assessments to consult.

In the first 3-5 years, a significant volume of oil will be produced. As the FPSO has storage capacity of 300 000 and the production plateau is 35 000 bod, the FPSO will have to be offloaded every one week. After plateau production, the offloading cycle will stretch.
Regarding gas it will be dried and pumped single phase through the pipeline, therefore there are no problems of waxing and hydrates. In this case only single phase booster stations are needed, which will be required every 100 km. Therefore, two booster stations are needed. The capacity of the new pipeline will be higher than that needed for the Bi an Phia Nan field so it can be used for tie-in nearby fields.