Soon after I joined the oil industry, one of our major producing reservoirs was downgraded and forecast to become non-commercial within 3 years. Within this window, the company was able to farm it out to a specialist oil company that worked on marginal assets. This was in 1999.
Further reassessments, wells, and 10 years later, the field was still producing oil at a rate higher than at the time of the farm-in. The remaining estimated producible reserves were close to the previous 12 years’ production.
In the US, the wells producing less than 10 barrels a day are called “stripper wells”. Certainly, these would be marginal by any definition, and mostly considered non-commercial. Yet, in the US, at the last count, there were 420,000 such oil and 360,000 gas wells in production, producing nearly 20 % of country’s output—not a mean number at all. The US National Stripper Well Association estimates that if these were all plugged and abandoned, the total economic market impact shall be of $52 billion and 240,000 jobs lost.
The experience in other countries is similar. Old wells need reworking and, often, assistance in creating the necessary pressure gradient. Three years back, the UK realised that the fields in the once-booming North Sea were now showing signs of ageing. As fields mature, the production falls, and it becomes difficult to support large fixed expenses. Reworking and looking for new wells cost big money. In the case of the North Sea, the hostile environment meant that the rig or platform lives were limited. Major capital expenses are involved in reclassification or replacement. In June 2013, an expert group, under Sir Ian Wood, recommended that additional fiscal benefits be provided to such fields to ensure their viability and maximise production. These recommendations have now been implemented.
India is energy-deficient. We currently import more than 75 % of our oil requirement and over 30% of our gas requirement. Even a 10% substitution of oil & gas imports through higher domestic production from marginal wells can save the nation approximately $1.5 billion every year. The impact of oil imports on our trade-deficit and the CAD can’t be taken lightly. If the government revenue drawn from this additional oil were zero (which can never be the case given the production taxes and royalty), the country gains substantially in terms of higher GDP, job creation, reduction in CAD and energy security.
When a field becomes old and the production curve is declining, if there exists a simultaneous high government profit-share, the asset is not as attractive as it can be. This situation frequently occurs when the original licence period expires and a renewal is needed. The government can either continue with the current operator or switch to a new operator or abandon the operation altogether. The licence contains abandonment responsibilities and site-restoration liabilities. Switching to a different operator gives rise to complex transition and liability issues, which could be a legal minefield. Consider, for example, the question of who would take care of an unanticipated environment liability. Will it be the old operator or the new operator who did not carry out the original development? The safety and environment costs/liabilities can be a fairly open-ended scenario. Therefore, the new operator either takes a risk on the existing plant and equipment with which it has little familiarity or replaces it, incurring high initial costs and loss of production. The oil-field-specific knowledge the old operator has gathered gets lost with the replacement of the technical team. Switching operators is, therefore, an option best avoided.
At this stage, typically, only one-third of the hydrocarbon content of the field would have been recovered. Thus, the renewal/marginal-field policy determines if the country has old fields that keep producing or it has unextracted subterranean hydrocarbon. Many countries now use technical means, like IOR/EOR, and commercial means, like additional fiscal benefits and incentives, to squeeze as much out of ground as possible.
Where does India stand? In the nomination era, no policy was ever pronounced, since it was all government-owned and managed, and production periods extended ad infinitum. With the opening up of the sector in the 1990s and the original licences nearing the end of their contract period, the new government is taking some creative steps to make these fields viable, and possibly even biddable, for E&P companies. This is a very welcome step.
However, India is not so logical when the private companies enter the scene. With contracted fields nearing the end of their licence, the government is bringing out a new extension policy. While the proposal has not been shared with the industry, media reports indicate that the government shall be seeking additional revenue from the old fields of private E&P companies. The extension shall be for a short period, rather than for the economic life of the field. Presumably, the government sees this as another opportunity to increase its take.
While some bean-counters and auditors may applaud the effort to raise additional resources, the actual impact could be the current operators abandoning the fields. With the marginality of the operation further reduced, insufficient residual life to make the capital expense for enhanced recovery and the uncertainty of timeline going forward, operator commitment would be reduced. Even if some of the ‘not yet marginal’ fields accept such conditions, the fact is that an increasing number shall shut down with time. This shall be a premature abandonment of the assets. Such an approach shall defy economic rationale. Old fields can go on, but you can equally easily kill them, too.
The author is secretary general, AOGO
Ashu Sagar