- The Barnett Shale will continue to be a significant player in shale gas production to 2030, at minimum.
- With natural gas prices expected to rise in time, the economics will be more favorable for E&P firms, possibly extending the production horizon of the play.
- This bottom up approach to well decline rates and estimated ultimate recoveries offers a better benchmark for investors sizing up Barnett wells.
- Demand growth in power generation will add to natural gas demand.
The idea of depletion captures the imaginations of everyone concerned about shale oil and gas, or energy in general for that matter. Estimates have changed, trending upward since the early part of the century. New facts, however, reveal that one of the major shale gas basins in the U.S., the Barnett Shale, is expected to be a significant contributor to natural gas production through 2030.
In 2013, the Barnett produced 5,306 million cubic feet per day (MMcf), even though firms have slowed down drilling as they refocus on oil and rich-liquids production. The price of natural gas has risen because of a very cold winter, but importantly, the continued trend of coal-fired power plant retirements may have implications for natural gas prices in the longer term. Since November of 2013, 5.4 gigawatts of power generation in Kentucky, Alabama, South Carolina, Michigan, Massachusetts and Georgia are to be retired. The movements are to comply with EPA regulations, weak demand growth and competition from natural gas generation.
A study by the Bureau of Economic Geology, University of Texas, Austin, "forecasts a cumulative 45 Tcf of economically recoverable reserves from the Barnett, with production declining predictably to about 900 Bcf/year by 2030 from the current peak of about 2 Tcf/year." They note that their forecast falls in the mid- to higher-end of other known predictions for the Barnett and suggests that it will continue to be a major contributor to U.S. natural gas production through 2030. Their estimates are nearly double that of the Energy Information Administration's July 2011 23.81 Tcf and the USGS year 2003 estimate of 26 Tcf.
In the second part of the study, the authors further refine their assessments. Of the 86 Tcf of technically recoverable free gas (TRFG) in 8,000 square miles, roughly 19 Tcf has already been proven and developed. They continue:
"[Of the] 67 Tcf remaining, 45 Tcf in drilled blocks and 22 Tcf in undrilled blocks. 45 Tcf TRFG in the 4,172-square mile drilled-block area exceeds estimates of 23.81 Tcf by EIA in July 2011 (4,000 square miles) and 26 Tcf by USGS in its 2003 assessment (5,000 square miles). "
In 1996, the Barnett was said to hold 3 Tcf, according to the United States Geological Survey (USGS). In 2008, at the time of my Barnett Shale article, Devon (NYSE:DVN), XTO Energy (now part of Exxon (NYSE:XOM)), Chesapeake (NYSE:CHK) and EOG Resources (NYSE:EOG) were the top four producers in that order. Devon Energy, still the largest producer in the Barnett Shale, plans to spend significantly less in the Barnett for a second straight year as it continues to focus more on increasing crude oil production. Many E&P firms are tilting toward oil and rich liquids production to maximize profitability. Devon drilled 172 wells in the Barnett in 2013, a 40% drop in capital outlays and wells from 2012.
The Bureau of Economic Geology study uniquely uncovers well-by-well analysis of production and calculates estimated ultimate recovery (EUR) for all wells. The authors base their analysis from the development of a physics-based decline curve that closely describes Barnett well declines, also a novel contribution. Their methodology is based on the physics of the system rather than on mathematical decline-curve fitting. Importantly, this development "should offer a more accurate method of forecasting production declines in shale wells in other basins." Their contribution is a major advance in projecting the decline of shale gas wells.
The study takes the production history of every well drilled from 1995-2012, then determines what remains to be drilled under various economic scenarios. They forecast field development from 2011-2030 and run production forecasts to 2050. The study assesses natural gas and liquid production potential in 10 productivity tiers and uses them to forecast future production. They analyzed over 15,000 wells for tier and decline curve analysis.
Source: Tinker, et al. "Barnett study determines full-field reserves, production forecasts.," Oil and Gas Journal, Sept 2, 2013, BEG UT Austin download.
"Actual field results for 2011 and 2012 were, respectively, 1,765 and 1,259 (3,024 total) new wells drilled and 2.09 and 2.07 Tcf (4.16 Tcf total) of natural gas produced from the field."
The Barnett Shale, of course, holds more natural gas than what is considered economic, as the study also sizes up. The authors calculate the volumetric original free gas in place (OGIPfree) of 444 Tcf for the 8,000-sq-mile study area. The Barnett field-wide is estimated to hold technically recoverable resources of about 86 Tcf, with technically recoverable resources for each square mile ranging from about 100 Bcf/sq mile in the top tiers to less than 20 Bcf/sq mile in the lower tiers.
The study authors note that the reservoir has considerable variation, with better performance blocks interspersed with poorer performance blocks and sometimes even better performing wells next to poorer performing wells within the same block. Ironically, the city of Fort Worth sits on top of some of the best parts of the reservoir.
In part two of the study, the EURs of the average 4,000-foot well are calculated per tier. (See Page 1 of study.) The top five tiers relay the following average EURs per well (Bcf of dry gas), respectively: 4.3, 3.0, 2.6, 1.9, and 1.4. The average lifespan of wells by top five tiers range from 25 years of production to 15. For comparison a tier six well has an 11-year production life for dry gas and a 24-year expected life for wet gas. (Their estimates are based on key assumptions on page 3.) For the top five tiers, considered "most important for the field," about 50% of EUR is recovered during the first 5 years, roughly 73% in the first 10 years, and 86% in the first 15 years. The actual average EUR recovered will be lower because attrition and economic limits will prevent some wells from producing for the full 25 years.
The study projects a base-case drilling of 14,073 new wells through 2030, adding to the 15,144 wells drilled through 2010, for a total of 29,217 wells drilled through 2030. (About 3,000 wells were accurately forecast to be drilled in 2011 and 2012 combined, leaving about 11,000 wells remaining to be drilled in the base case.) With expected capex of $3.5 million per well (among other costs), E&P firms could conceivably spend $38.5 billion (2014 dollars) to develop the resources over the next 15-20 years.
Source: Tinker et al. "Barnett study determines full-field reserves, production forecasts", Oil and Gas Journal, Sept 2, 2013.
Since drilling slowed, however, in 2013 and will in 2014, the projections for new wells drilled may now be pushed out further. In other words, rather than production peaking after 2015 or so, the peak could be deferred more in the latter teens. Add to this the Marcellus' primacy taking up E&Ps' current bandwidth with decent economics. These two factors, Marcellus primacy and slower gas drilling, can delay the peak of production. Exports are another factor. And then there is the part of the Barnett to the west with a higher liquids content. Pioneer Natural Resources (NYSE:PXD) calls this the Barnett Combo play. It contributes minimally to its overall production, however. The economics are different than in the predominantly gassy areas.
In general, with a Henry Hub price of $4.00, from 2011-2030, just over 14,000 wells are drilled for 36 TCF across a production period of 2011-2050. At a $6 price, 25,123 wells are expected to be drilled, resulting in 55.6 Tcf across the production span of 2011-2050.
The shale gas basins are not cratering anytime soon, as some suggest. More well depletion data based on actual performance is a terrific contribution to those concerned with energy security. As a result, investors can use better benchmarks and potentially more granular production forecasts with which to measure up firms' shale gas portfolios.