FLNG concept provides attractive development alternative

This case study involved an offshore concession 50 to 80 km (approx. 30 to 50 mi) from shore, in water depths ranging from 80 m to 120 m (262 ft to 394 ft) offshore West Africa. There is an estimated in-place volume of 1.0 to 3.0 tcf of non-associated gas (NAG). The concession lies on the continental shelf, between the shallow offshore area where significant discoveries have been made in the classic deltaic plays of Agbada formation, and the deepwater “outer trend” characterized by turbidic reservoirs of the Akata formation. This area is characterized by multiple plays of small to medium reserves of natural gas.

West Africa offers the possibility of a plethora of new LNG projects. Delays in realization of many of these proposed projects have been associated with uncertainties around feed gas supply. The characteristic absence of a spot market for gas places a high demand on a gas development concept study team to generate an “as-wide-as-possible” range of options in order to establish “at least” one feasible option. Two broad sets of alternative concepts are typically considered: standalone or satellite development. Detailed assessment is based on systematic identification, definition, and evaluation of the integrated production systems, namely: well host, processing host, production export facility and route, and destination(s). These systems are described below.

Well host concept

An unmanned “minimum facility” wellhead host protector (WHP) was adopted for this case study. The WHP allows for remote monitoring and control of the well facility from a central processing facility while minimizing maintenance and other operational routines. HSE risks to personnel are further reduced by minimizing frequency of visits to the well platform, thus reducing reliance on safety systems, which require yet more maintenance and testing to ensure reliability.

Although the WHP is adopted as the “base case” well host option for moderate water depths, subsea completion is also applicable and assessable. However, subsea tieback in shallow waters off West Africa has yet to be established. Generally, subsea costs are significantly higher than WHP for options involving long-distance umbilicals. Whereas from an operations perspective, WHP is preferred to subsea in shallow water, execution of subsea facilities projects are much simpler than the WHP option. From a security point of view, subsea may be preferred to WHP. Moreover, cost-wise, a subsea option would be competitive with WHP for floating solutions because of very short umbilical distance with fewer wells.

Near-shore development

Stand-alone development concepts (from Simprentis). FLNG development concept block diagram.

Onshore and near-shore gas processing concepts seek to lower project and operating costs and also to minimize risks to personnel by siting new (or using existing) gas processing facilities onshore or at near shore locations with the well host located deeper offshore. The well host can be either a “dry” wellhead platform or a “wet” subsea wellhead. The well facility is connected to the processing facility/platform via multi-phase subsea pipeline(s). Near-shore processing platforms will cover the process and utilities platforms, and a bridge-linked living quarters platform. Offshore-to-beach development is a good option for low capex when the distance to shore is short. The near-shore central processing facility (CPF) also provides for synergic development with other fields.

Challenges

Subsea flowlines are the principal way to move wellhead gas from an offshore location to onshore, near-shore, or existing receiving or processing facilities. The flowline is designed to carry wet gas and liquid/condensate under flow and seabed environmental conditions. The main challenge of an offshore-to-beach development is the cost of the interconnecting multi-phase subsea flowlines with umblicals, particularly for long step-out distances.

Also, the complex multi-phase flow of water, condensate, and gas presents potential for hydrate formation, internal corrosion, and severe slugging in the flowline. Use of special alloy pipes or carbon steel pipes with corrosion inhibitor injection, hydrate mitigation, and slug catcher facilities should be considered. These challenges translate into increase in lifecycle cost of flowline.

Stand-alone development

Offshore gas processing aims to treat wellhead gas to pipeline quality specifications, and then transport the gas/condensate via export pipeline(s) to a receiving facility onshore. The extent of gas/condensate processing – separation, dehydration, sweetening, stabilization, etc. – depends on the requirements of the receiving facility. A stand-alone offshore processing and compression platform includes an integrated wellhead, processing and living quarters, complete with all necessary utilities to support independent operation. Processed gas and condensate can be exported separately or commingled in a single pipeline, depending on the commercial terms.

Challenges

The main limit of fixed stand-alone development is high cost when compared to satellite options. However, when distance to shore is relatively far, a new stand-alone development on an appropriate platform can be considered. The integrated production facility can be on a fixed or floating platform, the choice of which depends on water depth and well count.

FLNG development

Various concepts for producing LNG on an FPSO have been developed. In this case study, FLNG was assessed as a field development option to determine its technical feasibility and economic viability for project execution. The FLNG concept involves the direct flow of wellhead gas from the WHP to a floating liquefaction plant, located about 2 km (about 1.2 mi) away. The FLNG plant consists of upstream gas pre-treatment facility, liquefaction trains, LNG offloading facility, LNG and associated condensate and LPG storage tanks, and mooring systems. Gas from the wellhead goes through the upstream separation and pre-treatment facilities before being fed to the liquefaction train and then the storage tanks. LPG will be stripped and stored, and condensate will be stabilized before storage in the tanks.

Upstream field facilities comprise only of the well host and flowline to the LNG FPSO as follows:

• Well platform – conventional piled steel substructure and topsides, remotely operated from the LNG vessel
• A 2-km (1.25-mi) carbon steel multi-phase flowline from the WP to the LNG vessel, complete with umbilical and a high integrity protection system (HIPPS).

FLNG system description

Here is a description of the proposed FLNG system:

Hull

• SPB storage tanks

Topsides equipment

• All upstream processing are covered by the floating LNG facility
• Gas treatment facility will include AGRU for CO₂ removal, molecular sieves for dehydration, mercury removal unit, LPG and C5 + removal
• N2 expander refrigeration cycle
• Booster compression will be required 10 years later to enhance the plateau production and recovery
• Trunk and moonpool for disconnectable buoy.

Topsides and storage capacities

• Liquefaction: 1.7 mtpa
• Feed gas: 270-300 MMcf/d
• LNG storage: 170,000 cu m
• Condensate storage: 50,000 cu m.

The upstream treatment facilities would include:

• Vessel type of slug catcher (1 x 100%)
• Gas liquid separation (1 x 100%) through an SMS separator
• Three-phase separator (1 x 100%) for water separation ahead of the condensate stabilization unit.
• Condensate stabilization unit (1x 100%) using packed column operating at 4.5 Bara
• Off gas from the condensate stabilization unit will be compressed and then routed to the fuel gas system
• Gas and condensate fiscal metering
• Produced water treatment and disposal.

FLNG challenges

Although the FLNG concept is based on two industry proven technologies – LNG and FPSO – there are technical challenges involved in adapting onshore LNG process and systems to offshore environments on an FPSO. Some of these challenges are identified. There are also new (and ongoing) technology solutions that address these technical challenges. These are identified below.

Topsides

Process considerations for adapting an LNG process on an FPSO include the following:

• Complexity and flexibility of the upstream gas treatment process and marinization of process equipment for offshore conditions of tilt motions
• Selection of appropriate refrigeration process that combines efficiency with safety, reliability, and availability requirements
• Minimization of equipment count and sizes.

Integration of topsides with the hull will rely on a deck layout that meets operational and safety requirements design.

Hull

Key issues include:

• Selecting suitable hull size based on available shipyard capability
• Concrete hull versus steel hull
• Appropriate containment system to minimize sloshing and enhance deck space.

Mooring and offloading

Offshore LNG transfer between FLNG and tanker is a significant challenge. Alternatives transfer concepts considered include:

• Side by side loading
• Offshore cryogenic loading.

A number of alternative process, utility, storage, and offloading technology concepts and systems have been developed for FLNG applications.

Assessment criteria

Assessment criteria for FLNG, along with the three “best practice” options – tieback to shore; tieback to near-shore; and new stand-alone – are as follows:

• Upstream project cost
• Production
• Project robustness – project execution risks
• HSE.

The selected concepts are compared on the basis of quantitative indicators such as production, ultimate recovery, and life cycle cost as well as qualitative indicators for project execution risk.

Upstream project cost

Cost estimates are prepared by multiplying engineering quantities developed for a defined project scope by unit cost rates. The upstream scope of the FLNG option includes the well host, multi-phase flowline, and cables. Field process facilities for gas processing and condensate stabilization constitute the FLNG (midstream) scope.

Field development capex and opex for the FLNG option is significantly lower than all the other alternatives due to substantial savings in pipeline and field processing facilities and hookup cost. Suitable tariff assumptions for economic evaluations were made for gas and condensate processing as part of the FLNG facility.

Production and recovery

Field production forecasts and ultimate recoveries were predicted for each development scenario using integrated production modeling and simulation software. Estimated rate and cumulative production data for FLNG field development were generated and analyzed with other options.

LNG production capacity of most FLNG facility developments is in the range of 1.5 mtpy to 3 mtpy. This leads to lower feed gas volume rate requirement (200 MMcf/d to 300 MMcf/d) per LNG train by FLNG compared to conventional onshore LNG plants (500 MMcf/d to 650 MMcf/d). The FLNG option can sustain a production plateau period of 16 years. In contrast, conventional tieback to onshore and standalone developments can only make six to nine years of production plateau from the same reservoirs. The gas to FLNG development option therefore offers the most feasible depletion rate for small to medium field reserves, leading to optimum economic life of the field.

Project execution risks

Assessment of project execution issues and risks is conducted by qualitative risk assessment methods. The FLNG option was assessed together with alternative development options on the basis of recent experience with offshore projects in the region.

The data suggests that overall project feasibility and impact of project risks – including EPC, local security as well as regulatory local content development (LCD) – for FLNG execution is in the “medium” range, comparable to fixed stand-alone offshore development project where applicable.

The key project risk with FLNG option is new technology risk. Use of local/localized engineering is an LCD requirement, but this is subject to scope of work. If less stringent LCD requirements are assumed in the view of the new technology risk factor, then the likelihood and impact of project risks on FLNG development in the region would be deemed to be “low impact.”

Conclusion

Identifying and selecting a feasible development concept is an integral part of a field development study. Tieback to shore and other satellite concepts currently offer the most cost effective strategies for upstream offshore gas developments, compared to a standalone development.

However, these options are limited to fields located near-shore or near existing infrastructure. An assessment of the FLNG concept shows that it minimizes the cost on flowlines and a separate onshore (or offshore) gas conditioning facility, thereby minimizing unit development cost for small distant offshore gas fields.

FLNG also allows for a longer production plateau which is optimal for a small field depletion case into LNG. In terms of project execution, the floating option provides for a potentially fasttrack delivery. The floating LNG concept could be actively considered as a “front burner” option for gas development opportunities in the area.

Acknowledgment

Based on a paper presented at the Offshore West Africa Conference and Exhibition held at the International Conference Centre, in Accra, Ghana, March 15-17, 2011.