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Enhanced Recovery through Subsea Compression
- Avinash Darekar, Principal Engineer | Area Engineering & Module Design Subsea Power & Process I, Aker Solutions
Subsea gas processing is the application of hydrocarbon processing equipment at the seafloor for conditioning and pressure boosting of reservoir stream fluids. Reservoir pressure in producing gas fields falls over time, causing gas output to decline. The article illustrates how does the Subsea Compression System helps in increasing the reservoir pressure in subsea gas processing to achieve the desired plateau rate.

In recent years, subsea gas processing has been recognised as one of the most promising technology developments in the offshore industry. Subsea gas processing is the application of hydrocarbon processing equipment at the seafloor for conditioning and pressure boosting of well stream fluids. With the recent successes at Åsgard Subsea Compression - Statoil and Ormen Lange Subsea Compression Pilot - Shell, subsea compression is attracting interest worldwide from industry because of its ability to increase production, enhance reservoir recovery and improve field economics.

Massive technology qualification programme has been part of Åsgard Subsea Compression and Ormen Lange Subsea Compression Pilot projects in which a large number of products have been qualified for use for subsea gas processing.

Subsea compression is, in general, still considered as an emerging technology. Therefore the benefits and capabilities must be clearly demonstrated to become the most preferred option.

Production Rate and Recovery
Initial reservoir pressure is usually sufficiently high enough for production by natural pressure for a number of years through a pipeline system connecting to topsides facilities. However, since production is invariably accompanied by a decline in reservoir pressure, plateau production soon comes to an end and starts its decline.

Pressure boosting the well fluid at this stage reduces the wellhead pressure on the wellhead and thus increases the production as seen from Figure 1.

At low flow rate, velocity of gas is not sufficiently high to continuously move liquid out of the pipeline; this condition is referred to as minimum hydraulic limit at which production cannot be sustained.

As compressor maintains flow rate of gas above hydraulic limit for some more time as compared to production by natural pressure, more hydrocarbons can be recovered from the reservoir as illustrated in Figure 2.

The Åsgard subsea gas compression project, with its two trains of state-of-the-art 11.4 MW subsea compressors, is expected to add recovery of an additional 280 million BOE.

Pipeline Sizing
Sizing of pipelines is traditionally made by finding a compromise between investment cost and available flow area. Large pipes are required at the end of field life to maintain high production rates when reservoir pressure has declined.

As gas production rate substantially reduces, the pipe reaches a hydraulic limitation characterised with the velocity of the gas which is no longer high enough to force the liquid out of the pipe. As it has been acknowledged that subsea compression will be qualified and available as required at the end of field life, it should be considered at the conceptual phase with regard to determining Cumulative Production pipeline size.

When a compression station is foreseen in late life operation, the selected pipeline may be made smaller since fric tional pressure drop can be overcome by compressor power and velocity of gas can be maintained above hydraulic limitation.

The subsea compression development will expand capacity in the Åsgard Transport pipeline, which carries gas from Norwegian Sea installations to the Kårstø plant north of Stavanger.

Compressor Location – Why Subsea?
Compression of gas may be done at three different locations in gas producing network:

1) At Onshore End: This is the cheapest of all other option but is inefficient. Excessive energy is requird to pull gas from subsea wells through pipeline network to onshore. Enhancing production by reducing well head pressure with this method would not be efficient due to very high pressure loss in the pipeline, caused by expansion of gas at lower compressor suction pressure which results in high actual volume flows. Volume expansion of gas is relatively much higher in lower pressure compared to higher pressure. A higher actual flow also leads to higher compressor power.

2) At Offshore: In this option, compressor is located nearer to the producing wells than the earlier option. However additional pressure drop may be created in the riser systems from the wells to the platform processing facilities, especially when platform is located in deep waters. Also this option incurs more capital cost as it needs suitable platform (either fixed or floating) for installing compressor and other facilities.

3) At Subsea: This is nearest possible location to the producing wells and is most efficient and needs less power as compared to other option discussed. It could add more economic value to the field if it is planned and considered in the field development plan at the early stage.

Modular Design of Subsea Gas Processing Station for Large Gas Fields
For large Gas fields such as Ormen Lange and Åsgard, subsea gas processing infrastructure can be modularised, consisting of a number of retrievable process modules. Each module will have a dedicated processing function. Together all the process modules installed and connected will perform the processing of the well fluid required.

Connections between modules will be made by mechanical and electrical connectors. A subsea process plant may therefore easily be configured for different functionalities, as long as interconnections and control system is planned for.

Modular design gives enough flexibility to cater to the changing requirements of producing gas field throughout its life.

Figure 3 shows a process train of Åsgard Subsea Compression Project, which comprises a inlet and discharge gas coolers, liquid separator and compressor modules, with the latter due to be powered from the Åsgard A oil production ship.

Compact Design of Subsea Gas Processing Station for Smaller Gas Fields
Realizing the need of production from smaller gas fields, subsea gas processing systems for fields, can be configured in one single integrated, compact, retrievable unit of reduced capacity of typically 2-10 MW.

The Compact GasBooster (Figure 4), which will enable the use of gas compression on a wider range of fields (small to medium size gas fields) and is well suited for deep water applications.

The proposed solution is of the same type as for Åsgard Subsea Compression System, however in a significantly smaller scale and with a simplified integrated and compact arrangement.

A GasBooster with a compressor utilizing 6 MW shaft power has been considered in an integrated system process simulation. The compression station is physically located near to the production wells. Furthermore, pipeline inlet pressure is 11 MPa. The compressor has a pressure ratio capability of 1:5.

Yearly production rates and accumulated production for production with natural pressure are in the following Figure 5 & Figure 6 compared with what is achievable with pressure boosting.

When plateau production no longer can be sustained by natural pressure, compression power is gradually increased to achieve the desired plateau rate. At a certain reservoir pressure, the compressor power is insufficient to maintain the plateau production. Hence, the rate corresponding to 6 MW input is produced.

The compressor power and pressure ratio is illustrated in Figure 7 below for declining reservoir pressure. Production is ended when a compressor ratio higher than 1:5 is required to maintain a minimum flow rate of 200 MMSCFD.

Summary
The selection of subsea compression for Åsgard and Ormen Lange in a fully sanctioned commercial project rather than opting for a new compression platform, Statoil and Shell has demonstrated that this technology is fully market-ready.

In order to get full economic value out of the field, E&P companies should consider employing this technology at the feasibility and conceptual stage of the development plan.

As it has been realised that the large producing fields like Ormen Lange and Åsgard are limited, more number of smaller fields are getting attention of E&P companies. Single, integrated, compact, retrievable unit of reduced capacity of typically 2-10 MW can be designed for smaller fields.