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    “Drilling Deeper” - A Reality Check?



"Drilling Deeper: A Reality Check on U.S. Government Forecasts for a Lasting Tight Oil & Shale Gas Boom" challenges US Dept. of Energy forecasts.

by: Drew Leifheit

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Natural Gas & LNG News, News By Country, Shale Gas , , Top Stories

“Drilling Deeper” - A Reality Check?

The US think tank Post Carbon Institute has recently released a report entitled "Drilling Deeper: A Reality Check on U.S. Government Forecasts for a Lasting Tight Oil & Shale Gas Boom," whose results question the US Department of Energy (DOE) scenarios for long-term tight oil and gas production.

Those DOE forecasts may be much too optimistic, according to the report's author, David Hughes, who has been a fellow at the Post Carbon Institute since 2006. Also president of the Global Sustainability Research Inc. consultancy, he says that in “Drilling Deeper” he sought to bring to the study as much factual data as possible, which he believes is lacking in much of the shale gas and oil information available thus far.

“All people have out there is industry presentations that obviously focus on the good wells. People want to raise money,” he explains, adding that's why he includes every well in the play in his analysis.

Combing through over 80% of the EIA's production forecasts for both tight oil and gas until 2040, Hughes says he was interested in coming up with a forecast of what the production profile would look like in US shale plays based on an understanding of well quality fundamentals in sweet spots and in the rest of the plays.

He says that for the Bakken current drilling rates run around 2,000 wells/annum with each well costing around $8 million, which translates to $16 billion/year going into the play. To offset decline, which is 45% per year, he says around 1,470 wells/annum are needed.

“So, they're drilling 500 more wells per year than you need to offset decline,” he remarks, “so production is going to go up.”

Mr. Hughes said he spent more time than he'd intended to compile and analyze the data necessary to forecast future production. In the Bakken, he says there are about 8,500 producing wells at present and it is likely possible, he opines, that 32,000 wells will be drilled before they are finished.

He noted that plays like the Bakken have “sweet spots”, which are highly productive and amount to a small part of the total play area. “As sweet spots are drilled off and drilling moves into lower quality areas, you've got to drill more wells to offset that 45% decline, because the wells don't produce as much but they still cost the same amount to drill – so you need higher prices in order to make it economic.”

His analysis suggests forecasts by the US Energy Information Administration (EIA), are overestimating overall long term production for most plays by 2040. In some plays, he added, the EIA is underestimating near term production rates and over-estimating production rates in later years.

Of their estimate of the gas in the Marcellus shale, for example, he explains, “Although I agree that 129 trillion cubic feet is not unreasonable, I don't agree with the production profile. I think a lot more of the production is going to be front-loaded, so we'll see higher production sooner and low production later in the long-term.”

In comparison, Mr. Hughes says his forecast for the seven major shale gas plays he analyzed ends up totaling about 39% less total production than the EIA by 2040, and only about one-third of the EIA's forecast production rate in 2040. “That has fairly serious implications if you're talking about building a lot of LNG export facilities,” he comments, adding that 20-year contracts at guaranteed prices are necessary to build a $10 billion LNG plant.

Drilling Deeper, he says, is based upon a the Drillinginfo commercial database, which he regards as one of the best databases of well production data available. He recalls, “What I wanted to do was basically take apart those plays and look at all of the fundamentals: decline rates, well quality by area and number of available drilling locations.”

Mr. Hughes says he broke the information down by county for most plays.

“Every shale play usually has a core area or a sweet spot,” he explains, “which may be 10-15% of the total area of the field, so by taking thing apart on a county level one can look at the variation in well quality – in the sweet spots, and in the rest of the play.”

This included looking at fundamentals like how fast wells decline. Typically, he says, shale wells will go down 80-85% over the first 3 years. “It's a hyperbolic decline, so the first year can be in the 70% range, second year maybe 30%, third year maybe 25%. And then if you look at the field as a whole, it is composed of old wells and new wells: new wells are going down the quickest while older ones go down more slowly.

“If you look at field declines for a play like the Bakken for example, it's about 45% per year, so if you didn't drill a well, production would fall by 45% in one year. If you know the average first year production rate of the wells that are drilled, it's quite easy to figure out how many wells you need to drill in order to offset the decline,” he says.

The higher production goes, the bigger proportion that 45% represents, he explains, meaning that more wells need to be drilled to offset decline as production rises.

In his study, he says, despite explorers' negative cash-flows, he assumed capital would not be a problem – the money will be there to drill the wells and that concerns about the environment would not restrict access to drilling locations.

In his projections, Mr. Hughes says he sought out to map out the production profiles given various drilling rates. “Drilling Deeper,” he says, gives high, low and most likely drilling rate scenarios, which can be related to future commodity prices.

“Drilling rates are of course dependent on price,” he explains. “In my view, trying to forecast price is a guessing game. I prefer to deal strictly with the physical realities of the play fundamentals and drilling rates, and I've put enough scenarios out there so that people could say, 'yeah, price is up so maybe we should be tracking on the fast drilling rate scenario.'”

Meanwhile, Drilling Deeper may also throw into question the DOE's price forecast of less than $6/thousand cubic feet until 2030, but Hughes contends that once drillers move out of the sweet spots being drilled now and into lower quality parts of plays that have much lower well production rates, a much higher price is required. “The idea of cheap, abundant gas for the foreseeable future at low prices is not correct – prices are going to have to go higher,” he says.

Still, he says both gas and tight oil production is likely to grow until 2017-18.

“There's always a miracle that could happen – an undiscovered Marcellus could be found, a couple more Bakkens and Eaglefords could be found, but people have been looking fairly intensively, so I think it's a fairly low probability that that's going to happen.”

This could mean substantially higher prices in 3-4 years, he adds.

“Bearing in mind, if you stop drilling these plays fall off like a rock – the Bakken goes down 45% in one year. You have to keep pouring capital into them,” says Mr. Hughes.

Given his analysis, he says that there is some likelihood for the export of US shale gas to Europe in the short-term. He offers, “If you look at the Sabine Pass LNG facility, it's supposed to start exporting at the end of 2015. I certainly wouldn't count on it as being any sort of an antidote to Europe's dependency on Russia for gas. I think that the people who are investing in those LNG facilities are likely to be disappointed.

“If you look at the cost of shipping LNG to Europe, liquefaction, shipping and regasification costs about $6/MCF. If the price is $4, then that's $10 in Europe, which is still competitive,” he explains. “But if the price in North America goes to $6, then all of a sudden that profit margin's almost gone, and if it went to $8 then you're far better off selling it in North America than to Europe, because it is no longer competitive.”

He adds that with the increasing amount of natural gas being burnt instead of coal in America, as well as the repatriation of manufacturing based on cheap gas, more inelasticity is being built in to the US gas market: “There's a lot of new demand coming on for gas that's going to have to be served, regardless of what happens to price.”

David Hughes spent most of his career working for Canada's Geological Survey, where he worked on coal, coal bed methane, and unconventional gas in general. “For the last 15 years or so, I've been on the speaking circuit on global energy, so I’ve looked at all aspects of energy, globally and in North America,” he explains. “Over the last few years I've been particularly interested in the shale revolution and what that means for the future.”

Drew Leifheit