DENVER—IHS CERA Research director and advisor Stephen Trammel has a message that no one in the business really wants to hear.

He cited IHS statistics showing that the 2013 global oil discovery rate of 13 Bbbl of oil was the lowest it has been since the 1952 rate of 8 Bbbl of oil. The numbers also show that 2014 discovery volumes should be 30% lower than the previous year.

“With drilling up and fewer discoveries, and success rates going down, the number of new field discoveries has fallen by 50%. Field sizes are on a slow, downward trend for both conventional and unconventional oil and gas. The largest recent discovery in the past two years was 900 million barrels in the Kwanza Basin in Angola,” Trammel said at the June Energy Finance and Discussion Group meeting.

He also said that of all new recent discoveries, about 59% are gas.

“The number of global conventional oil and gas field developments has continued its decline, but it fell off the cliff. Since 2013, conventional gas field discoveries have declined even more rapidly.”

He continued, “Rising exploration activity costs and declining conventional field discoveries are driving the rates down. Previously, about 25% of well activity would end up as a success, and now that number has fallen to 14%. While all of this has been going on internationally, North America has been going on the opposite direction and the rest of the world is watching us with the unconventional oil and gas revolution.”

Trammel said that offshore basin activity has continued to attract a lot of capital since 2013. “Offshore still has the biggest return and the biggest productivity, despite onshore being the most dominant. Deepwater has accounted for 50% of all conventional discoveries over the past four years.

“Where most of the capital is going now is to develop the new discoveries, like Brazil, and that takes about five to seven years to really get those going. There’s not as many new discoveries going on and some countries have been hampered by sanctions, embargoes and wars like in Iran and Iraq, and even Israel is taking its time in developing its field. All of that adds to the bleak picture.”

Cost increases, according to Trammel, have moderated but are still expected to rise about 8% to 10%.

“We are projecting price increases out to 2017-2018 and it will squeeze the economics if we’re not getting production discovery volumes,” he said. “The upstream returns we’re seeing now are because of these volumes, but the average return on capital employed has fallen off. Before the worldwide recession in 2006-2008 we were seeing about 30% average return on capital employed, and now it’s hovering around 15%.”

Majors are cutting their E&P budgets by as little as 15% and by as much as 50%, according to Trammel.

“And there are still substantial above-ground risks to be dealt with. There is a lot of anti-fracking sentiment all over the world now. You also have to deal with land issues, and are there trained and available crews and equipment to do the work, and is there enough water available to do the job?”

Future possibilities

Despite some obstacles, Trammel said the news is not all bad. Australia, Africa, South America and the Middle East could have more growth. Other areas that have possibilities are in the Chukchi Sea, offshore Greenland, maritime offshore Canada, the Russian Siberian Arctic, offshore east Africa, central Africa and even some deepwater offshore Australia.

In a global tight oil study that it released in 2013, IHS revealed that there are 148 different plays that could have as much as 288 Bbbl in recoverable oil.

About 33 countries, led by Argentina and China, have licensed shale oil development. “The rocks are out there in the unconventional plays to offset the slowdown in conventional discoveries.

“Mexico is a place with all kinds of new opportunities. The Sureste Basin has oil and associated gas of about 20 million barrels onshore and 41 million barrels offshore. The Tampico-Misantla Basin has 13 million barrels of oil and associated gas. The onshore Burgos Basin is in onshore northern Mexico, and it’s a southern extension of the Maverick Basin in Texas, which is still largely unexplored.”

He also said that the Veracruz Basin has 119 Bcm (4.2 Tcf) of gas. The Akal Field, which is part of the Cantarell complex, has reserves of 16.5 MMboe.

According to Trammel, only a handful of unconventional wells have been drilled in Mexico. The wells are dry gas and produce about 4 to 5 MMcf/d of gas. More exploration and drilling and expertise is needed to develop production, he commented.

Opportunities also exist for technology advancement in unlocking heavy oil. “In Utah, I know of projects that are underway to heat up kerogen-rich rocks to try to create 65 million years’ worth of heat to turn that kerogen into oil,” said Trammel.

The conventional production decline can also be offset by developing heavy oil fields, such as those found in Canada and the Middle East.

“Growth from known fields is the ace in the hole, going back into conventional fields and applying unconventional technologies. The sweetest parts have already been drilled and we’re going back into the marginal areas, such as the Delaware and Permian Basins and the East Texas fields. New recovery techniques now make these economically feasible.”

Trammel noted that Alberta’s Cardium play is another example of developing a known field. The Cardium has been in production since the 1950s, and recent horizontal drilling is creating new production. “One of the advantages in the Cardium is the low proppant and water volumes required for production, especially when you compare it to the Eagle Ford and the Bakken. You don’t have to spend as much money to complete these as you do a shale or tight-zone well

“I think this has a big upside potential and I think we’ll see that kind of work going on in mature fields before we see pure unconventional drilling take off in an area. From a capital investment standpoint it makes a lot of sense. The risk factors are low.”