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Just how much shale gas is out there? A research team takes a comprehensive look at data from four U.S. plays to figure out some estimates for ultimate gas production By Alan Bailey Petroleum News
Although the upsurge in production from shale oil and gas plays in North America has revolutionized people’s views on future energy production in the region, there have been widely different forecasts of just how much new hydrocarbon resource might result from so-called unconventional development and, hence, how long the new energy bonanza might last.
To try to inject some objective facts and analysis into what can easily become an exercise in fuzzy speculation, a team based in the Center for Energy Economics in the University of Texas and funded by the Sloan Institution has been conducting a detailed technical and economic assessment of gas production in four U.S. shale gas plays: the Barnett, the Fayetteville, the Haynesville and the Marcellus.
The team has now completed its analysis of the Barnett and Fayetteville, concluding that at a gas price of $4 per thousand cubic feet 45 trillion cubic feet of gas may come from the Barnett by 2050, with 18.2 trillion cubic feet ultimately coming from the Fayetteville by that same point in time, Gurcan Gulen, senior energy economist at the Center for Energy Economics, told the International Association for Energy Economics’ North American Conference on July 30.
Gaps in knowledge Gulen commented that one reason for wide disparities between different shale gas estimates is the existence of gaps in knowledge about the physics of the gas fields.
“That’s why you see a lot of debate out there, a lot of people questioning the resource base,” he said.
The Center for Energy Economics team tackled the question of estimating shale gas resources by approaching the problem from the perspectives of the geology of the shale gas basins, the production characteristics of wells in the basins and the economics of drilling and operating the wells, Gulen explained.
Geologic analysis From a geologic perspective, the team obtained well log and seismic data, using these data to develop basin maps. One type of map for the Barnett, for example, depicts the multiple of rock porosity and thickness, a parameter that gives indications of the likely relative productivity of different parts of the basin, showing where the “sweet spots” for shale gas drilling are likely to lie. An overlay of a well productivity map onto this map confirmed that high well productivity coincided with promising geologic indications, Gulen said.
The geologic model indicated that there may be about 444 trillion cubic feet of natural gas in place in the Barnett shale, with about 280 trillion cubic feet of gas in place in areas where there are current producing wells, Gulen said, emphasizing that these volumes are much larger than the volumes of gas likely to be technically or economically recoverable from the rock.
Well performance From the perspective of well performance for the Barnett shale, the team obtained production data up to 2010 for about 16,000 wells, with the team using the data for about 15,000 of these wells, rejecting 1,000 wells that had poor quality data.
The team used the data to derive a well production model and production decline curves, to gain insights into future well behavior. The decline curve model, using the physics of gas flow through fractures stimulated around a well during well fracking operations, produced a curve that showed “a fairly decent fit” with production decline plots from several hundred actual wells, Gulen said.
From estimates of the subsurface drainage area of each existing well, the team estimated how much of each play might remain available for future shale gas development and, hence, how many additional wells could theoretically be placed in the play. However, the team significantly trimmed back its expectations for the actual play area that might be developed and the number of wells that might be drilled by allowing for the fact that there are urbanized areas, for example, where drilling will not take place, and the likelihood that areas not currently being developed are going to be relatively less attractive for future drilling than the more productive areas.
Economics From an economic perspective, the team investigated well costs and evaluated break-even points for viable shale gas drilling. Then, using its estimates of available play areas, potential well densities and likely well production rates, the team was able to derive a model for the future gas production outlook, based on likely future drilling rates, factoring in possible gas prices and likely drilling costs.
In doing this for the Barnett, the team grouped wells into 10 distinct tiers, each tier having different geologic, production and economic characteristics. In the Fayetteville the team distinguished six distinct tiers of wells. And, recognizing that recent low gas prices have caused the drilling focus to shift towards “wet” gas wells, producing natural gas liquids as well as “dry” natural gas, the analysts also separately considered wet and dry areas of the Barnett shale. In the Fayetteville, where the depth of drilling apparently significantly impacts drilling costs from one well to another, the team grouped wells into three different depth ranges.
The production outlook models resulted in the 45 trillion cubic feet and 18.2 trillion cubic feet cumulative gas production estimates for the Barnett and Fayetteville shale basins.
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