In a world of accelerating decline rates, depleting reserves and LNG uncertainty, unconventional gas plays in the Lower 48 are something to be excited about. This is particularly true of the burgeoning Barnett Shale play in the Forth Worth basin of north-central Texas.
The U.S. Geological Survey completed an assessment of the Fort Worth basin Barnett Shale a few years ago. Findings were published in the American Association of Petroleum Geologists' AAPG Bulletin in February 2005. The article says the play has "multi-trillion cubic foot potential."
Indeed, how about 30 Tcf. Rich Pollastro, a USGS geologist who worked on the survey, told NGI that he and his colleagues estimate 26.2 Tcf of technically recoverable undiscovered reserves in the core and extended areas of the play. Add this to what's already been booked to reach 30 Tcf. And there could be more to come as the play is expanded and technology evolves.
"Since we did our assessment and outlined sort of the main gas area for the Barnett, the play just kind of went crazy," Pollastro says.
What makes the shale interesting to this geologist and others is, well, the shale. Traditionally considered either a source rock for petroleum or a seal rock, shale was not thought to be a repository for natural gas. "Now that we've used up most of our conventional resources, the shallow, porous sandstones and carbonates, we now are looking at these deeper, tighter rocks," Pollastro says.
The most actively drilled area of the Fort Worth Barnett Shale is the Newark East field, which is the largest gas field in Texas, according to the AAPG Bulletin article co-authored by Pollastro. Newark East is more than 400 square miles with more than 2,340 producing wells and about 2.7 Tcf of booked gas reserves. Newark East wells produce at rates ranging from 0.5 to more than 4 MMcf/d, and estimated ultimate recoveries per well range from 0.75 to 7 Bcf.
An October 2005 report by Pickering Energy Partners Inc. called the Barnett Shale the hottest gas play in the U.S. and said that with $6/Mcf gas, "Barnett drilling is full steam ahead." But it's not always smooth sailing, even in a play as hot as the Barnett.
"Significant variability of well results exists even within concentrated areas," Pickering writes. "As the industry has yet to figure out how to identify the good wells from the bad (yes... there are bad wells in the play), a large acreage position is a necessity in order to minimize the risks and allow the law of large numbers to take effect."
Shale gas fans owe a big nod to George Mitchell for detecting gas in the Barnett and sticking with the play while technology evolved to get the gas out. "They stayed with that play for about 15 years and really drove the technology to try to stimulate the shale and get the gas to move enough to make it economical," Pollastro says.
Mitchell's success did not go unnoticed and Devon Energy completed its acquisition of Mitchell Energy in January 2002 (see NGI, Aug. 21, 2001). By that time the company had drilled about 700 wells in the Barnett Shale over about a 20-year period, according to Devon. The new owner quickly stepped up the pace, drilling about 1,300 wells in the Barnett since acquiring Mitchell. Devon also is a pioneer of horizontal drilling, which has proven to be highly advantageous in the Barnett Shale.
Last year the company drilled about 210 Barnett wells, about 150 of which were horizontal. This year Devon expects to drill about 280 wells, 75 to 80% of which will be horizontal. Today Devon has about 2,000 wells on production in the Barnett producing about 575 MMcf/d. That figure is expected to grow this year, but by how much remains to be seen.
"Those wells, of course, are depleting every day," says Jeff Hall, Devon exploration manager. "Each and every one of those wells produces a smaller volume than it did the previous year, so... it takes an enormous amount of effort just to stay flat and make up for that decline. To grow production is pretty phenomenal in a big project like this."
Pickering's report notes that Barnett Shale well performance peaked in 2000 and has trended down since then. "Possible explanations include the Newark East field continuing to mature and companies attempting to expand the field outside the sweet spot. We expect the production trend to reverse in future years as the focus in the play continues to shift to horizontal wells from vertical wells, which have higher production rates."
Pickering also says the initial decline rate for Barnett wells drilled in 1999 through 2003 was 52% in 1999 but has since averaged 65%. "We think the latter is a better estimate for future forecasts as recent vintage decline rates have consistently been in the mid-60% range."
Devon is by far the largest producer in the Barnett, with five times the production and nearly five times the acreage of XTO Energy, which holds second place, according to Pickering. Devon has 18 rigs running in the Fort Worth basin and will probably increase that number this year, Hall says. Devon is directing more of its Barnett activity outside of the field's core area, which is composed of Denton, Wise and Tarrant counties. That trend began in 2004 and continues. Pickering reports that a new Barnett Shale sweet spot is developing in Johnson County, "which looks superior to much of the 'core' acreage beyond Newark East."
The Barnett's low-porosity, low-permeability used to suggest the need for sophisticated frac'ing technology with lots of chemicals and gels. Devon and others have found greater success using an "East Texas" or light sand frac on their wells -- lots of water and a relatively small amount of sand for proppant. A more recent effort to grow production came last year when Devon sought and received permission from the Texas Railroad Commission to downspace its Barnett drilling to 20-acre spacing.
The Barnett is different from other shales in that it is not naturally fractured, Pollastro says. "The gas within the Barnett is tied up with organic matter. It's a very tight rock; it's almost like pool table slate. One of the secrets is that the Barnett is slightly over-pressured, so gas moves toward the lesser pressure and it moves out of these tiny, tiny pores.
"This is not a fractured shale play. It's what they call a 'shale-that-can-be-fractured play.' And now they're going into all these shales that seem totally impossible to produce, and it's working because the technology has driven this play to be economic."
Pollastro says some of the lessons learned in the Barnett Shale are now making the Woodford Shale attractive. "It's a crazy thing," Pollastro enthused. "I think they're going to start exploring for these things globally, too, Australia, South America. The Barnett has gotten a lot of people's attention."
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