Tech
Shale Gas Output Decline: Study Determines Numerical Model
Staff Reporter
First Posted: Mar 04, 2013 03:11 PM EST
One of Americas largest shale gas formations, the Barnett, was examined in depth for its future gas production potential by the Bureau of Economic Geology (BEG) at the University of Texas at Austin. Shale gas exploitation and forecasts concerning the future development of the sector and market are of great importance for US energy production and policy, but also pose challenging geological and engineering problems on the way.
The new study foresees slowly declining production through the year 2030 and beyond by integrating engineering, geology, and economics in a numerical model that allows for scenario testing based on many input parameters.
This forecast neither lends to the overly optimistic nor to the sudden collapse worries and plots out an average trend line for the production from the Barnett shale and suggests that the formation will continue to be a major contributor to US natural gas production through 2030.
In the base case, the study forecasts a cumulative 44 trillion cubic feet (TCF) of recoverable reserves from the Barnett, with annual production declining in a predictable curve from the current peak of 2 TCF per year to about 900 billion cubic feet (BCF) per year by 2030.
The BEG study examines actual production data from more than 16,000 individual wells drilled in the Barnett play through mid-2011. Other assessments of the Barnett have relied on aggregate views of average production, offering a “top down” view of production, says Scott Tinker, director of the BEG and co-principal investigator for the study.
The BEG study, in contrast, takes a “bottom up” approach, starting with the production history of every well and then determining what areas remain to be drilled. The result is a more accurate and comprehensive view of the second most productive shale region in the US.
The study’s model centers around a base case assuming average natural gas prices of $4 for a thousand cubic feet but allows for variations in price, volume drained by each well, economic limit of a well, advances in technology, gas plant processing incentives and many other factors to determine how much natural gas operators will be able to extract economically.
“We have created a very dynamic and granular model that accounts for the key geologic, engineering, and economic parameters, and this adds significant rigor to the forecasts,” says Svetlana Ikonnikova, energy economist at the BEG and co-principal investigator of the project.
“Drilling in the better rock won’t last forever,” says Tinker, “but there are still a few more years of development remaining in the better rock quality areas.”
The data in the model stop at the end of 2010, after approximately 15,000 wells were drilled in the field. In the base case, the assessment forecasts another 13,000 wells would be drilled through 2030. In 2011 and 2012 more than 2900 wells were actually drilled, in line with the forecast, leaving just over 10,000 wells remaining to be drilled through 2030 in the base case. Wells range widely in their ultimate recovery of natural gas, a factor the study takes into account.
A new method of estimating production for each well, based on the physics of the system, was integral to the project and should offer a more accurate method of forecasting production declines in shale gas wells. This method, along with several other components in the workflow, has been submitted in several manuscripts to peer-reviewed journals.
According to BEG, their papers have already undergone a form of professional peer review built into the research process by inviting an independent review panel with members from government, industry and academia to critique their research before submitting the papers to journals. Research funding was contributed by the Alfred P. Sloan Foundation.
FAQ and study: University of Texas at Austin
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First Posted: Mar 04, 2013 03:11 PM EST
One of Americas largest shale gas formations, the Barnett, was examined in depth for its future gas production potential by the Bureau of Economic Geology (BEG) at the University of Texas at Austin. Shale gas exploitation and forecasts concerning the future development of the sector and market are of great importance for US energy production and policy, but also pose challenging geological and engineering problems on the way.
The new study foresees slowly declining production through the year 2030 and beyond by integrating engineering, geology, and economics in a numerical model that allows for scenario testing based on many input parameters.
This forecast neither lends to the overly optimistic nor to the sudden collapse worries and plots out an average trend line for the production from the Barnett shale and suggests that the formation will continue to be a major contributor to US natural gas production through 2030.
In the base case, the study forecasts a cumulative 44 trillion cubic feet (TCF) of recoverable reserves from the Barnett, with annual production declining in a predictable curve from the current peak of 2 TCF per year to about 900 billion cubic feet (BCF) per year by 2030.
The BEG study examines actual production data from more than 16,000 individual wells drilled in the Barnett play through mid-2011. Other assessments of the Barnett have relied on aggregate views of average production, offering a “top down” view of production, says Scott Tinker, director of the BEG and co-principal investigator for the study.
The BEG study, in contrast, takes a “bottom up” approach, starting with the production history of every well and then determining what areas remain to be drilled. The result is a more accurate and comprehensive view of the second most productive shale region in the US.
The study’s model centers around a base case assuming average natural gas prices of $4 for a thousand cubic feet but allows for variations in price, volume drained by each well, economic limit of a well, advances in technology, gas plant processing incentives and many other factors to determine how much natural gas operators will be able to extract economically.
“We have created a very dynamic and granular model that accounts for the key geologic, engineering, and economic parameters, and this adds significant rigor to the forecasts,” says Svetlana Ikonnikova, energy economist at the BEG and co-principal investigator of the project.
“Drilling in the better rock won’t last forever,” says Tinker, “but there are still a few more years of development remaining in the better rock quality areas.”
The data in the model stop at the end of 2010, after approximately 15,000 wells were drilled in the field. In the base case, the assessment forecasts another 13,000 wells would be drilled through 2030. In 2011 and 2012 more than 2900 wells were actually drilled, in line with the forecast, leaving just over 10,000 wells remaining to be drilled through 2030 in the base case. Wells range widely in their ultimate recovery of natural gas, a factor the study takes into account.
A new method of estimating production for each well, based on the physics of the system, was integral to the project and should offer a more accurate method of forecasting production declines in shale gas wells. This method, along with several other components in the workflow, has been submitted in several manuscripts to peer-reviewed journals.
According to BEG, their papers have already undergone a form of professional peer review built into the research process by inviting an independent review panel with members from government, industry and academia to critique their research before submitting the papers to journals. Research funding was contributed by the Alfred P. Sloan Foundation.
FAQ and study: University of Texas at Austin
See Now: NASA's Juno Spacecraft's Rendezvous With Jupiter's Mammoth Cyclone