Abstract

Liquefying natural gas on an offshore facility servicing an underlying gas field has yet to be sanctioned anywhere in the world, in spite of several feasibility studies demonstrating its potential viability. The perceived risks associated with deploying unproven technology in a high construction cost and volatile gas price environment have so far inhibited offshore liquefaction projects. Such technology however has the potential to unlock substantial volumes of remote and otherwise stranded natural gas for commercial exploitation.

With strict no flaring aspirations in many countries discovering associated gas can pose obstacles to developing an oil field if no gas utilization strategy is commercially viable. Key issues for offshore gas liquefaction processes are: compactness (low weight -small footprint), ease of operation, process safety, and efficiency.

Particular attention is paid to the lower-efficiency turboexpander processes for plant capacities up to 3 million tons per annum (MTPA, about 0.43 Bcf/d). These cycles offer several advantages over the alternative optimized cascade and mixed refrigerant (MR) liquefiers..

Introduction

Increasing global demand for natural gas is supporting the rapid growth and diversification of worldwide LNG production capacity. As demand continues to grow, the value of natural gas remains high in the major consuming markets. Such a situation enhances opportunities and promotes motivation to monetize more difficult and remote gas resources. Projects developing medium scale gas reserves or gathering associated gas from a number of remote oil fields represent challenging targets for development in the absence of existing gas-handling infrastructure. The few large gas fields that exist are more likely to be developed by conventional land-based liquefaction plants, based on pressures placed by governments on the international oil companies (Wood and Mokhatab, 2006).

The future potential to deploy floating liquefaction probably lies in medium size gas fields, or aggregations of smaller fields with associated gas, developed by medium sized independent companies. However, the restrictions of more stringent no-flaring rules being introduced in some prolific countries (e.g. Nigeria and Angola) may prompt some existing offshore producers of giant volatile oil and wet gas fields to aggregate gas from several such fields and develop large-scale (> 4 MTPA capacity) floating liquefaction as an alternative to building and operating expensive gas re-injection facilities. The potential to unlock offshore gas reserves without the need to invest in capital intensive pipeline infrastructure, infield platforms and onshore infrastructure and to minimise exposure to geopolitical and security risks makes offshore gas liquefaction options worthy of close scrutiny..

Process Design Criteria

Offshore natural gas liquefaction is edging closer to technical and commercial viability. Process design criteria such as compactness, weight, modular design, process safety, minimizing weather-related downtime and storage sloshing impacts are important to offshore designs. Offshore floating liquefaction has generated interest because it offers the potential to (Barclay and Yang, 2006):

  • avoid flaring or reinjection of associated gas

  • monetise smaller or remote fields of non-associated gas

  • reduce exposure to public and increase security of facilities

  • lower LNG production costs

The expanding uptake of large barge-mounted floating production, storage, and offloading (FPSO) facilities offshore West Africa for oil fields with associated gas and LPG production, for example, (e.g. Shell's Bongo field in Nigeria), Total's Girassol field, Exxon's Kizomba field and Chevron's Sanha field in Angola), indicate that high capacity facilities for handling gas offshore can be deployed on a commercial and safe basis.

This content is only available via PDF.
You can access this article if you purchase or spend a download.