Globally, natural gas development is surging ahead, and several major projects are progressing. Fields such as Norway’s Ormen Lange and India’s Dhirubhai lead the big players, with many huge fields to follow, such as Russia’s Kovykta and Shtokman and Australia’s Jansz and Gorgon.

With the upsurge of new production, is there any room to develop further stranded gas?

Awaiting development approval means prior to FID and government approval. These fields are not proceeding on a firm schedule or could possible be delayed indefinitely. (All graphics courtesy of IHS)
The latest release of IHS’s “World Petroleum Trends” suggests the answer to that question is “yes.” The report indicates more than 1,500 Tcf of natural gas has been discovered, but is not yet in production.

The lay of the land
Of the 1,500 Tcf of discovered natural gas, just 280 Tcf is currently under development, which amounts to approximately 17% of the available resource. Russia’s Shtokman and Kovykta fields account for nearly half of the 17%. The report lists majority of the 1,500 Tcf of gas (61%) either as discovered with no activity or is in the early phases of appraisal.

Large-scale liquefied natural gas (LNG) and international transmission pipelines are the conventional routes to market for major consumers in the United States, Europe, Japan and Korea. But during the last few years — and for many to come — China and India are joining the queue to fulfill their massive energy needs and to mitigate the negative environmental effects of their recently built coal-fired power stations.

The greatest challenge that natural gas development is facing is not a question of whether the gas is available, but whether it can be developed at a low enough unit cost to justify the massive investments needed to cover market risks.

Natural gas prices rose from more than US $6/MMBtu in 2005 (except for a spike to $16/MMBtu following hurricanes Katrina and Rita) to around $8/MMBtu in late 2007. Construction costs, meanwhile, rose by 72% in the same period, as measured by the IHS/Cambridge Energy Research Associates (CERA) Upstream Capital Costs Index.
So how does this affect the development of stranded gas as a resource?

Developing stranded gas
The question of defining what is stranded gas and determining how it can best be monetized has been around since gas exploitation began. However, for purposes of simplicity, there are some basic categories that demonstrate the size and status of the remaining recoverable, non-producing resource: developing, awaiting development approval, appraising and discovery. Because 61% of the identified resource does not currently have a monetization option, it must be defined as fully stranded.

While the CIS holds the most non-producing resources, much of the gas is under development to fulfill the region’s emerging domestic gas demand and to maintain its
Number of stranded gas fields in various size ranges.
international gas contracts. To deliver this gas, however, a massive infrastructure development program will be required, which in turn will increase the volume of potentially economically viable resources and increase the desire of companies to step up exploration.
The Far East contains the most significant stranded-gas opportunities. With the 46-Tcf Natuna field (Indonesia) excluded, the remainder of Indonesia, Malaysia and China contain more than 30 Tcf of gas each.

Iran contains 85% of the resources currently under appraisal in the Middle East, with most of the gas in the Pars North, Kish 2, and G3 fields.

Beyond the Middle East, the world’s most significant quantities of remaining stranded gas in the appraisal and discovery categories are in Australia, Nigeria and Norway.

Monetization options
The main use for natural gas is power generation. Envionmentalism is influencing the move to natural gas, as is the political will in the west to reduce carbon footprints. Gas-to-wire power generation is likely to be the main driver for natural gas usage. Gas growth is likely to exceed average GDP growth and increase in the proportion of the primary energy slate.

Most of the gas used in countries with large gas power portfolios is imported via pipeline or is supplied by LNG re-gasification terminals. When the distance to market exceeds approximately 2,484 miles (4,000 km), the LNG route makes more economic sense, provided a viable sea route exists.

Other uses
for gas include chemical and petrochemical feedstock, fuel for energy intensive manufacturing such as aluminum smelting, and the manufacture of cement. These outlets provide reasonable to good returns for producers; however, the volume needed for these products is fairly limited when compared to power or transportation fuels. The potential change to this status will occur if methanol-run fuel cells become a viable transport option.

Large-volume conversions to make synthetic oil such as gas-to-liquids (GTL) appears to be highly desirable as it produces clean fuels for transport (clean diesel), but the process is very inefficient in energy terms and is costly. GTL requires low-priced natural gas to make it work. In areas where vast amounts of low-cost natural gas are available (such as Qatar, Iran, and Russia), GTL makes sense as part of a portfolio of monetization options.

Economic solutions
Current and conventional thinking says as the bulk schemes of LNG and GTL grow in size, the economies of scale will reduce the overall unit price of the commodity and allow it to compete against domestic supplies. The cost of large-scale or specialist equipment is rising faster than smaller-scale or standard equipment due to shortages of supply.

This short supply is being driven by a lack of investment in production, infrastructure and refining over the last 20 years and the fact that all of these facilities are now required to support the economic growth currently taking place and to bring online the spare capacity needed to stabilize oil, gas, and product prices. Price escalation in building these facilities has created a shortfall of development plans, which extends the shortage of supply despite an abundance of energy sources.

The extent of this cost increase is evident in the reported unit cost of LNG during the last two years, which had dropped from around $600/ton when LNG commercialization began to approximately $250/ton in the early 2000s, resulting from efficiency gains achieved through larger compression systems. Recent reports claim this cost has now risen past $650/ton, to nearly $800/ton, and there is speculation that the newest LNG plants could rise to approximately $1,000/ton. These costs are clearly unsustainable.

Significant cost increases are also reported in GTL plant-builds, resulting in a number of GTL plants being put on hold — post Pearl GTL in Qatar, for example.

When considering the exploitation of stranded gas, the unit cost of natural gas is the key driver. If costs are not controlled, the margins required for investment cannot be realized to cover the large risks required to deliver supply to a variable market. These costs are made up of three main elements:
• Capital cost;
• Operating cost (including transportation, re-gasification and storage); and
• Taxes (including those imposed by the resource holder as well as the consuming country).

Capital costs have doubled or tripled, partly because of skill and material shortages, and partly due to inflation and predatory pricing, which enables incumbents to price gas higher. The only means of mitigation would be to develop procurement and contracting strategies that reduce or avoid single-chain dependencies or to create competition by choosing more standard elements in the buildup.

In this scenario, size is temporarily removed as a cost-efficiency driver and is replaced by availability of goods and services, where cost-efficiency can be achieved. The onus is on owners to repackage contracts, which will require them to increase their technical and project management efforts to cope with the changes or reward contractors that can do it for them.
There is greater potential for mini-bulk conversion options, including mini-LNG, mini-GTL, and methanol, that use conventional and readily available equipment. “Mini” options offer two advantages: more choices for the producer and lower capex. Volumes are more easily placed in the market without flooding, which can cause local price dips.

So, if the industry is to take advantage of this segment of the market, there is potential in relatively small-field exploitation (local power or mini-LNG/GTL options) and very large field development, where size still does work, but allows possible cooling of the market and employs mitigating sizing and service placement where possible.

IHS analysis indicates fields less than 1 tcf and fields greater than 5 tcf are advantageous to develop. There are ample field opportunities across the board, with more than 200 fields in the 0.5-1 tcf range and more than 40 fields that contain 5 tcf or more.

Stranded-gas opportunities exist for every type of player to play to their own strengths and where taxes for exploitation are reasonable or negotiable to suit a plan that is right for them. This approach may need to be more inventive and could even involve sharing risk through the gas chain, which means sharing the upside as well as the downside.