Subsea Field Development Assessment
For subsea field development, field layout designs are selected based on historical data obtained from other projects, and various brainstorming and discussion sessions with teams from all other subdisciplines. Critical design factors may consist of, but are not limited to, the following:
- Engineering and design;
- Cost and schedule involved;
- Well placement and completion complexity;
- Flexibility of field expansion;
- Ease of construction and fabrication for the subsea hardware;
- Intervention capability (easy, moderate, or difficult to intervene);
- Rig movement (offset from mean under extreme environmental conditions);
- Installation and commissioning, such as ease of installation and commissioning, flexibility of installation sequence;
- Reliability and risk of the field architecture;
- ROV accessibility.
The inputs from the entire project team are used to assign percentage weights to each of these design factors. Normally, all of the various types of field layout designs, such as the subsea tie-back, subsea stand-alone, or subsea daisy chain, can be applied in the field. Reliability, risk assessment, and economic balance are the dominant factors when deciding what kinds of field layout will be chosen. The following material presents an overview of the available means of adding energy to the production fluid and assessing the best location for the artificial lift to be introduced in a generic deepwater field development. The objectives are:
- To evaluate the artificial lift options including lift gas, electrical motordriven pumps (ESPs or multiphase pumps) and hydraulic submersible pumps (HSPs);
- To determine the best location (riser base, subsea manifold, or downhole) for artificial lifts using lift gas;
- To determine the best location for installing electrical motor-driven pumps for artificial lifts (ESPs downhole versus multiphase pumps at subsea manifold or riser base);
- To determine the best configuration (open loop versus closed loop) for installing an HSP in a riser in conjunction with coiled tubing for artificial lift.
- Pressure ¼ 8000 psia;
- Temperature ¼ 200 F;
- Well PI ¼ 20 bpd/psi;
- Reservoir pressure maintenance by water injection.
- True vertical depth (TVD) ¼ 11,000 ft from mudline;
- Tubing size ¼ 5.5-in. OD (0.36-in. WT);
- Kick-off point ¼ 2,000 ft below mudline;
- Kick-off angle ¼ 45;
- Roughness of tubing ¼ 0.0018";
- U value for wellbore ¼ 2.0 Btu/(ft2 hrF).
- Water depth of 8000 ft;
- Subsea well completion, dual flowlines, three identical wells per flowline;
- Tie-back distance from subsea manifold to topsides (flowline þ riser) of 25,000 ft;
- Steel catenary riser, pipe-in-pipe configuration considered for both riser and flowline with an assumed U value of 0.2 Btu/(ft2 hr F);
- Seabed terrain assumed to be flat;
- Typical environmental conditions including seawater temperature profile and air temperature were used;
- Riser/flowline roughness ¼ 0.0018 in.;
- 10- and 12-in. nominal riser/flowline sizes were evaluated.
Correction to the inflow performance with regard to increased water saturation of the reservoir has not been made.
An increase in water production occurs much more slowly in this depletion case than would be the case if water injection for pressure maintenance was included. The water-cut profile is described as a function of accumulated liquid from the reservoir.
When a volume of liquid of 30 million cubic meters (Mm3) has been extracted from the reservoir, the water-cut has reached about 99%. The total volume of oil produced to the topsides specification is shown next when 30 Mm3 liquid has been extracted.
Process simulations have been carried out with HYSYS process simulator. The OLGAS correlation has been applied for pressure drop calculations in pipe segments. The model is illustrated in Figure 2-26, showing a simulation of a multiphase pump at the riser base in a situation when 5 Mm3 liquid has been produced from the reservoir.A series of simulations are performed for various reservoir accumulations to establish the liquid production from the reservoir as a function of the reservoir condition. These simulations are then repeated for the various production cases that are investigated. The time it takes to produce a certain volume from the reservoir is calculated by integrating the liquid rate function with regard to volume accumulation.
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 M. Faulk, FMC ManTIS (Manifolds & Tie-in Systems), SUT Subsea Awareness Course, Houston, 2008.
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