Just reading the headlines, it seems that the oil and gas industry continues to find enough hydrocarbons to power the world for centuries.

Recent highlights include:
• Statoil, which announced its eighth discovery in Block 2 offshore Tanzania in March;
• Kosmos Energy, with a significant find offshore Mauritania;
• W&T Offshore, announcing a discovery at Ewing Banks Block 910 in the Gulf of Mexico (GoM);
• Pemex, reporting major oil and gas discoveries in the shallow-water GoM with estimated reserves of 350 MMbbl;
• Exxon Mobil, with its Liza-1 discovery offshore Guyana; and
• Eni, which discovered a “supergiant” gas field offshore Egypt.

These are just the offshore discoveries. Onshore, both conventional and unconventional reservoirs continue to be discovered or developed.

But a recent report by Richmond Energy Partners, “The State of Exploration,” indicates that all is not rosy on the exploration front. The study, released in April 2015, examined the exploration success in 2014, a year in which oil prices were robust until the November downturn. It was not a pretty picture.

Declining performance
It’s not that the industry stopped exploring. It’s just that the results were often disappointing.

In the executive summary, several conclusions were drawn:

  • Discovered volumes and average commercial success rates in 2014 were at a seven-year low;
  • 2014 was a record high for frontier drilling, but the success rate remained less than 10%;
  • With the cost structure prevailing before the oil price downturn, more than 50% of the discovered fields were uneconomic at $60/bbl oil;
  • Some exploration strategies have been more successful than others, and these vary greatly even amongst companies with the best track records. “[Having] focus and discipline is the most reliable route to sustained performance,” the summary noted. “This old mantra may have been forgotten in the heady days of $100-plus per barrel oil prices;” and
  • Conventional exploration continues to be relevant since low-cost-to-produce discoveries can still be made. “Lower oil prices herald an era of more focused exploration, albeit on an opportunity set tempered by the lack of frontier success in recent years,” the summary noted.

Keith Myers, a managing partner at Richmond Energy Partners, explained that this study has been conducted for several years. It reviews exploration performance over a five-year period.

“What’s become apparent is how poor the performance was in 2014, and that’s even before the oil price crashed,” Myers said. “Exploration was already facing headwinds.”

The summary noted that commercial volumes discovered in 2014 were the lowest in five years, a 42% drop from 2013 and more than a 60% drop from the peak discovery year of 2012.

Geographically, only nine of the 131 basins drilled resulted in more than 500 MMbbl of gross oil discoveries.

“The presalt Santos play remains by far the most significant oil play to have emerged this century, and the presalt of the Kwanza Basin is the only other [greater than 1 Bbbl] oil province discovered since 2008,” the summary noted.

The study examined four companies that were the most successful in terms of volume: Lundin, Tullow, Talisman and Cobalt. The differences in their strategies were notable. Cobalt, for instance, has a presalt and subsalt focus and is very much play-focused on deepwater. “These are expensive wells,” Myers said. “In the case of the [GoM], it was expensive to access acreage as well. They spent nearly $1 billion on leases.”

Talisman has taken more of a geological focus, including foreland basins in Colombia and fold belts in Kurdistan. Lundin has focused on overlooked plays in proven mature basins, while Tullow has pursued the most diverse strategy both geographically and in terms of play maturity.

Gas discoveries have not been the issue. It’s oil discoveries that are scarce; hence, the study focused on successful oil finders. Myers said that the gas discoveries flattered the boe number, so statistics on a boe basis look more positive than the numbers for oil discoveries alone.

“There were a record number of frontier wells drilled in 2014,” he said. “But the success rate of these wells hasn’t significantly improved in terms of yielding new commercial plays, particularly for oil. The plays that have emerged have been relatively modest in scale; very few of them have been more than 1 Bbbl in size.”

Can technology help?
Exploration technology has made enormous strides over the past couple of decades, but sometimes it’s still not enough to help these numbers along. “The maintechnical reasons for failure of the frontier wells are reservoir [presence and quality] and charge access [migration],” the summary noted. “3-D seismic technology is not changing the performance of frontier drilling. For example, since the 2007 Jubilee discovery, of the 67 frontier wells that targeted analogous deepwater Upper Cretaceous prospects at a cost of [$6.85 billion], there have been just two commercial discoveries—one oil at Barra in Brazil and one gas at Mzia in Tanzania.” Exxon Mobil’s Liza discovery in Guyana has recently added a third.

Added Myers, “The issue is that often when oil is being found, it’s not in commercial-quality reservoirs. Especially in the plays that have a stratigraphic component, it’s essential to have 3-D seismic. But it has not led to an improvement in frontier success rates from a commercial perspective because of the difficulty in mapping effective traps and good-quality reservoirs.”

So what’s the problem? Myers said that questions abound. Is the industry not finding the emerging oil plays because they’re not there to be found? Do explorers have the right tools? Are companies drilling in the wrong places?

“We have opinions, but we don’t have the answer,” he said. “It’s certainly not from lack of effort. The industry has been trying very hard and throwing a lot of money at it. But it hasn’t cracked the code.”

However, with lower oil prices come lower costs for technology. In a recent presentation, Dr. Nick Cooper, executive director and CEO for Ophir Energy, noted that the current exploration market offers “a compelling opportunity.”

“The risk profile of the geology has not changed, but the cost of assessing the subsurface risk has fallen dramatically,” he said. “It is well documented that rates for both seismic vessels and drilling rigs have fallen, but perhaps the most important change is that licences for prime acreage can now be acquired without having to undertake firm drilling commitments.

“We believe this is a fundamental change that will lead to improved returns from exploration drilling as our geoscientists will be able to highgrade across our portfolio without the encumbrance of drilling commitments on specific licences.”

A change in strategy
In many cases, high-risk wells were drilled for reasons other than an expectation of a huge discovery, such as the aforementioned commitments made in bid rounds or acreage acquisitions. There also was an increased appetite for frontier drilling after the 2009 downturn.

“The larger companies all tend to move together, and they decided that frontier was the thing,” Myers said. “So they all increased their level of frontier drilling.”

Given the current downturn, companies are expected to return to a more conservative approach. Richmond Energy partners expects a 40% drop in exploration drilling in 2015 and a change in focus toward nearfield, faster-to-develop discoveries.

“Exploration is still relevant if you can make low-cost-to-develop discoveries that are economic at $50/bbl oil,” Myers said. “Conventional exploration still has a place in oil company strategy. But there has to be more focus than there has been, and inevitably that means fewer wells.”

The summary noted that at a benchmark price of $70/bbl, a large number of discoveries made between 2008 and 2014 become unviable at current capex and opex levels. “The assessment shows that standalone oil fi elds of [100 MMbbl] in shallow water may only just be economic at current prices and costs, and standalone deepwater discoveries need to be [greater than 250 MMbbl] in size,” it stated.

The future of frontier exploration
With a more sober approach, it’s likely that this dismal trend can be reversed. The Exxon Mobil discovery is a good case in point. The discovery well, based about 193 km (120 miles) offshore Guyana, encountered more than 90 m (295 ft) of high-quality oil-bearing sandstones. The Stabroek Block upon which the well was drilled covers an area of 26,800 sq km (10,348 sq miles). Currently Exxon Mobil and its partners, Hess Guyana Exploration Ltd. and CNOOC Nexen Petrolum Guyana, are analyzing the data to determine the full resource potential.

“This could lead to excitement in Suriname and Guyana,” Myers said. “Liza will be sure to stimulate activity as long as the border dispute doesn’t hinder things too much. Nothing is ever simple politically, unfortunately.”

Other areas that hold potential are the Mexican GoM and Atlantic Canada, he added. But with continued depressed oil prices, a quick bounceback in exploration is unlikely.

“It would require a material success somewhere in a new play opening up to see a big step-up in exploration,” he said. “But reduced activity might not be a bad thing. The industry was drilling a lot of very expensive dry holes, which was not helping the overall situation.

“We’ve got to get these high-risk exploration wells in plays that don’t seem to be working out of the system, and then the industry can move on again.”

Also read:

Reward Awaits Those Willing To Explore During Downturn