According to Kris Anderson, of the Sustainable Gas Institute (SGI), the average size of natural gas fields that are being discovered is becoming smaller, and that has an impact on the profits of investors
During a recent lecture to Professors at the Research Centre for Gas Innovation – RCGI, researcher Kris Anderson analyzed and compared different subsea technologies for producing petroleum and natural gas, and he warned: the use of these technological tools must make sense economically, because there is a big possibility that investors could lose money with small natural gas fields. Anderson is a researcher for the Sustainable Gas Institute (SGI), headquartered in the United Kingdom, and is a specialist in the development and commercialization of technologies for separating petroleum and natural gas.
“We know that the average size of the fields being discovered is diminishing. The small offshore natural gas fields are intrinsically of little value. They do not have much to be taken, so we must be careful to know whether it is economically viable, because, depending on the situation, there is a serious possibility that investors will lose money in that case.”
According to Anderson, the CAPEX – investment in capital goods dedicated to offshore structures – could often cost more than the value of the gas itself. “Even if there are profits, they might not be big enough to justify the risk investment,” he stressed. The reason for this discrepancy is the very nature of the activity, along with the complexity and costs of so-called subsea technologies. Generally speaking, that refers to all of the technologies applied to undersea exploration.
Available technologies – Anderson lists different options for developing offshore fields: Fixed Platform (FP); Compliant Tower (CT); Tension Leg Platform (TLP); Mini Tension Leg Platform (MTLP); Spar Platform (SPAR); Floating Production System (FPS); Shuttle Tanker; and Floating Production, Storage and Offloading System (FPSO).
“Brazilian offshore work, for example, is too deep for using TLPs, and most of the fields have been developed with the use of FPSOs. The depth of the water makes subsea systems an automatic prerequisite. Floating production systems have an advantage over SPARs and TLPs, specifically because they float. On the other hand, the SPARs are usually transported to the site in separate parts that are assembled there, in the ocean. But the SPARs are more stable than the TLPs and can shift laterally by adjusting their moorings,” he explained.
The researcher also said that a variety of factors come to bear on the choice of one or another exploration technology in specific situations. He separates these factors into four groups: production factors, reservoir factors, the operating environment, and other issues regarding the development of underwater technologies. “Each one of these factors has its variables. And all of the variables must be factored into a possible model of the exploration process. For example: when the ocean floor is very uneven, it is exceedingly complicated to lay down pipelines more than a thousand kilometers long, because the operating environment could make costs rise.”
He states that subsea technologies, like increased outflow of petroleum and compression, only became commercially viable about ten years ago, thanks to long-distance tiebacks (subsea connections between a new oil and gas discovery and an existing production unit). Anderson explains that the use of these tiebacks presents advantages and disadvantages.
“Among the advantages are the monetization of inactive assets and the prolonging and better usage of the existing infrastructure. Furthermore, its quick installation makes possible a shorter wait to achieving peak production levels. The wells can be drilled closer to the desired site, thus reducing drilling costs, and the CAPEX is less than that of an offshore platform.”
On the other hand, the tiebacks could cause flow guarantee problems and are not adequate for highly complex reservoirs. “Besides that, intervention in those structures is difficult and quite expensive, and the final recovery of capital will be less than what is obtained with a production platform that has drilling capabilities. And, despite being less than that of a dedicated offshore platform, the investment in capital goods is still relatively high, on the order of several hundred million dollars,” he points out.
According to Anderson, even if modeling is done, you never know how much return a natural gas field might generate. In order to handle these uncertainties, he applied the Monte Carlo simulation, (a technique that quantifies the uncertainties of risk predictions), using several specific cases as examples. “Instead of trusting a single-point estimate analysis, you can simulate a variety of possible results, in order to better understand the probability of success.”