With floating production, storage, and offloading (FPSO) vessels headed for the US Gulf of Mexico as early as 2001, there has been a flurry of interest in stranded natural gas alternatives. While a number of technologies exist to convert free and associated gas for transportation, cost, weight, and size have emerged as key stumbling blocks to finding a pipeline alternative.
The stranded gas question is not a new one, and while the current focus seems to be offshore, the fact is a viable onshore solution could offer operators a lucrative new market for massive fields now considered too remote to produce.
Conoco is investing in the development of an efficient gas-to-liquids process to address the vast amount of stranded gas it has identified onshore. Paul Grimmer Manager of Diversified Businesses for Conoco, said current estimates are that 4 quadrillion cubic feet or more could be stranded in fields around the world. This is gas already identified, and in many cases, ready to be produced. All it lacks is a viable market.
Transport issues
For the most part, the challenge onshore or offshore is how to transport this gas to market at a competitive price. This is why natural gas discoveries become stranded in the first place. While onshore issues keeping the industry from developing known reserves appear similar to those facing offshore development, there are a number of advantages. Chief among them are:
- Onshore facilities do not have such massive premiums on space and weight that a floating facility would have
- Physical stability - a shore-based facility does not heave and sway with the sea
- Onshore siting does not require specially designed shuttle tankers to transport production.
Grimmer is charged by Conoco with evaluating alternative methods of dealing with stranded gas for Conoco. He identifies which of the existing and emerging alternatives show promise and which are not commercially viable. He does not believe any alternative gas strategy makes sense for the majority of fields offshore.
For several reasons, he does not think it is practical to try and compete with the economics of a pipeline, when looking at stranded gas solutions specifically in the deepwater Gulf of Mexico. Very large onshore plants also are not economically viable, due in large part to high capital costs. Still, offshore gas rates are much less than some of the huge stranded gas fields identified on shore.
This causes an increase of as much as 50% in capital costs per barrel for gas captured and transported offshore because economies of scale are lost. In addition, onshore costs typically increase by 40-50% when taken offshore. Together, these factors double the costs on a per-barrel basis for technology in a market that can't tolerate cost increases.
Pipeline solutions
Even if Conoco was to consider a gas-to-liquids (GTL) solution for an offshore field, Grimmer said, the company would most likely pipe the production ashore first, process it there, and then convert it. With current and emerging technology, Grimmer said GTL would require vast reserves in the neighborhood of 3 tcf to justify the costs of bringing such a system online.
These offshore reserves would have to be so isolated from their market that transportation via pipeline would be impractical. While such fields do exist, and are the drivers for Conoco's current effort, they are mainly onshore. It is hard to imagine, Grimmer said, a field in the Gulf of Mexico so isolated from the mature pipeline grid that it would be cheaper to convert and ship the gas ashore.
Grimmer concedes that stranded gas solutions onshore and offshore reduce to the question of transportation costs. The very large gas fields his company has identified would be profitable if there were a local market for the gas. As it stands now, when an operator strikes gas in the Middle East, for example, the well is plugged and abandoned. The transportation costs are just too high to justify a development.
The deepwater Gulf of Mexico situation is different. These are not true gas fields for the most part, but rather oil fields with various quantities of associated gas. This gas must be dealt with somehow, either through flaring, reinjection, or pipeline. Grimmer agrees with Paragon Engineering Services President Ken Arnold, that no matter how this gas is handled, it is not going to turn a profit. The gas simply must be disposed of in the most economical way.
Gas alternatives
One promising option Grimmer has looked at is re-injection to store produced gas for future power consumption. Grimmer said there is often a lot more gas pressure in the early stages of a well than later in the field's development. Typically, in the early stages of development, the amount of gas produced will be more than what is required to run the rig. The excess could be injected into the formation or possibly a convenient aquifer. As the gas pressure head on the field begins to decrease, the stored gas could be brought on-line as a power source to run the rig.
While there are a number of novel solutions on the drawing board, Grimmer said the required infrastructure and logistics make most of these impractical. For example, if LNG was an option, Grimmer said a huge offshore plant would be required to clean and compress the gas, then special ships would transport it to shore. One of these ships would have to be onsite at all times to manage the continuous flow of gas from the well.
This would hold true for any of the compression or refrigeration solutions. The costs quickly outweigh the benefits, Grimmer said. A pipeline is expensive to install in deepwater and it is difficult to maintain flow, but these costs are for the most part a known quantity.
As the pipeline grid continues to expand, the question is not whether a pipeline can reach a given deepwater field, but will the operator tolerate the fees required to tie production into the offshore pipeline grid, which moves production to the major onshore pipelines.
This, he said is one of the main drivers for bringing FPSOs in to the Gulf of Mexico. However, if an operator is using an FPSO to get around tying oil production into the pipeline grid, is the producer also willing to tieback gas production? For the time being at least, Grimmer said there is little choice.
