Shale Gas: Penn State Researchers Rediscover Circular Reasoning


Guest “are you fracking kidding me?” by David Middleton

Researchers unearth cost-effective method for finding shale gas
New method approximates available gas in untapped areas of Marcellus Shale region using well production data

David Kubarek
September 03, 2019

UNIVERSITY PARK, Pa. — A new method for exploring natural gas in the Marcellus Shale, developed by Penn State researchers, shows potential high yield areas can be found more easily and with lower costs.

Traditionally, natural gas hot spots are determined using a combination of current well production data and various geological tests. The researchers, in work published in the SPE Reservoir Evaluation & Engineering journal, detailed a method for approximating available gas in untapped areas using well production data taken from more than 5,600 existing wells.

Researchers used only wells with more than two years of production logs and assigned a decline curve analysis — the amount of production loss over time — for each well. They then applied these decline curves over the entire region of the Marcellus Shale. That allowed researchers to forecast the amount of gas that would be generated over time if a new well were created. Researchers then validated their findings using geological maps, which were created from core samples.

“Rather than looking at these geological proxies for production we’re just looking at production itself,” said Eugene Morgan, assistant professor of petroleum and natural gas engineering in the Penn State College of Earth and Mineral Sciences. “By looking at just production and mapping we see that it agrees really well with these geological variables related to production, which validates our approach. By looking at production alone you’re directly targeting the information you’re after.”

Morgan said the method held strong during validation, showing that it was almost as effective at forecasting natural gas resources as methods that include costly geological data sampling.

[…]

Penn State University

This map accompanied the article and includes the actual caption:

Penn State researchers detail a method for approximating available gas in untapped areas using well production data taken from more than 5,600 existing wells
“Penn State researchers detail a method for approximating available gas in untapped areas using well production data taken from more than 5,600 existing wells in the Marcellus Shale region. That could lead to more economical location of natural gas with less disturbance on the region’s geology. IMAGE: PENN STATE”

That could lead to more economical location of natural gas with less disturbance on the region’s geology.

Penn State

“Less disturbance on the region’s geology”???

The purpose of drilling and frac’ing gas wells is to disturb the region’s geology. That’s how you get the gas to come out of the rocks and go into pipelines If you don’t disturb the geology, you don’t produce oil or gas… You can’t even drill and produce a groundwater well without disturbing the geology.

In fairness to the Penn State researchers, the press release was clearly written by someone who was totally clueless.

The SPE paper is pay-walled, but clearly not written by someone who was totally clueless.

Combining Decline-Curve Analysis and Geostatistics To Forecast Gas Production in the Marcellus Shale

Zhenke Xi (Pennsylvania State University) | Eugene Morgan (Pennsylvania State University)

To estimate the production potential at a new, prospective field site by means of simulation or material balance, one needs to collect various forms of costly field data and make assumptions about the nature of the formation at that site. Decline-curve analysis (DCA) would not be applicable in this scenario, because producing wells need to pre-exist in the target field. The objective of our work was to make first-order forecasts of production rates at prospective, undrilled sites using only production data from existing wells in the entire play. This is accomplished through the co-Kriging of decline-curve parameter values, where the parameter values are obtained at each existing well by fitting an appropriate decline model to the production history. Co-Kriging gives the best linear unbiased prediction of parameter values at undrilled locations, and also estimates uncertainty in those predictions. Thus, we obtained production forecasts at P10, P50, and P90, and we calculated the estimated ultimate recovery (EUR) at those same levels across the spatial domain of the play.

[…]

SPE Reservoir Evaluation & Engineering journal

This is all well and good. In resource plays, like the Marcellus, decline-curve analysis (DCA), all by itself, can pretty well forecast the estimated ultimate recovery (EUR). The production data can be used to forecast production… Not a new concept and basically circular reasoning. Furthermore, the authors clearly state that this is for”first-order forecasts of production rates.” It’s a reconnaissance tool. By interpolating DCA’s play-wide, you can identify areas which may be more prospective than others, in resource plays. This might help high-grade areas on which to focus more detailed geological analyses; although most geologists will want to work the schist out of the entire play. You don’t find things that everyone else missed using this sort of methodology.

However, this is not “a new method for exploring natural gas in the Marcellus Shale”… It’s not a method of exploring for anything. Nor does it show that “potential high yield areas can be found more easily and with lower costs.” You still have to pick a drilling location. And the only way you can do this is to interpret the geological data from nearby wells and incorporate any geophysical data that are available. The drillers have to have a target (x,y and depth).

One of the problems with science communication is that press releases are often far-removed from the scientific publication and then misreported by the media.

The new method of exploration comes at the right time. Demand for natural gas in the United States is growing, but prices have been depressed because supply from the shale patch is growing faster than demand. As a result, in April this year, the benchmark natural gas contract at the Waha Hub slipped into negative territory, at  -$9 per million British thermal units. Just a month later, the benchmark slipped into negative territory once again, at -$4.28 per mmBtu. The average price for the first five months of the year was $0.92 per mmBtu.

At the end of August, natural gas was trading above US$2 per mmBtu, but analysts warned that soon they could slip lower than this as summer ends and temperatures fall, undermining demand, which spiked during the heat waves. Now, there will likely be a lull in demand before it picks up during the winter.

Despite the lower prices, U.S. natural gas production continued to increase in August and set a new daily production record of 92.1 billion cubic feet per day on August 5, the EIA said, citing data from OPIS PointLogic Energy. Between May and August, gas production rose by 2.5 percent, mainly driven by the Northeast.

In this price and supply context, the new exploration method, if applied on a larger scale, could have implications for U.S. LNG exports as well.

Oil Price Dot Com

“The new method of exploration high-grading comes at the right time” for what? With natural gas prices routinely falling into negative territory and averaging less than $1/mmBtu, nothing can make drilling natural gas wells economic, except NGL’s…

Confidence in this fast pace of production growth is well-founded; reported initial production rates and other factors suggest that the break-even gas price for many dry Marcellus producers is only about $2.50/MMBTU, and that—thanks to supplemental returns on natural gas liquids (NGLs) and, in some cases, condensates—the break-even gas price for many wet Marcellus/Utica producers is even lower: about $2/MMBTU. In some cases the effective natural gas breakeven price gets all the way to zero, with fortunate producers achieving breakeven returns from the sale of NGLs and condensates.

RBN Energy

Production data is usually purchased from vendors who specialize in aggregating production data. Well logs and other geological data are also usually purchased from vendors. These sorts of data aren’t expensive, particularly in comparison to seismic surveys. And all of these costs are insignificant compared to the cost of drilling and completing the wells.

Even if this high-grading tool works and is widely employed, it would just increase the volume of natural gas production, putting downward pressure on prices. Re-quoting the Oil Price Dot Com article…

The new method of exploration comes at the right time. Demand for natural gas in the United States is growing, but prices have been depressed because supply from the shale patch is growing faster than demand.

Oil Price Dot Com

A new tool that increases production and barely affects costs is not coming at the right time, when natural gas is ranging from -$10/mmBtu to +$2/mmBtu.



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