Independents' innovations pay off in prolific Barnett shale play
Petroleum geologists and engineers worked for decades to unravel the secrets of economically producing natural gas from the enormous Barnett shale formation in north central Texas, and the efforts are paying off.
Although federal tax credits helped stimulate early efforts in this play, drilling activity has accelerated since the expiration of the Sec. 29 Nonconventional Fuel Credit in late 1992—proving that the play is economic on its own without government incentives.
The former Mitchell Energy & Development Corp. made the first economic completion in the Barnett shale in 1981 and then spent 20 years developing fracturing technologies to improve the performance of wells there (OGJ, Jan. 19, 2004, p. 45).
Devon Energy Corp., Oklahoma City, acquired Mitchell in January 2002, acknowledging that it was very interested in the Barnett shale assets. Currently, Devon and its service partners continue to advance fracturing technology for the play.
The Barnett shale's boundaries have yet to be delineated by drilling. Numerous producers are working to expand the limits of the known commercially productive territory, where dense shale still requires persistent efforts to recover the gas.
Industry currently estimates recoveries at 10-15% of the original gas in place. The latest technology to advance industry's efforts in the Barnett shale is the use of horizontal drilling in both the core and the noncore areas.
W. Mark Meyer, analyst with Simmons & Co. International of Houston, said the play's future rate of production growth hinges upon the success of horizontal drilling, particularly beyond the core area (Figs 2a-2b).
Devon is "transitioning" from depending on vertical-well technology to seeing if it can obtain a sustained production growth rate from equivalent drilling levels of horizontal wells, he said.
"Certainly, Devon is enthusiastic about what it has seen so far, but the jury is still out on the growth leverage," Meyer said. "Producers are in the early stages with horizontal drilling, and small tweaks on drilling or completions can make a difference in the economics."
He also noted that XTO Energy Inc., Fort Worth, acquired properties in the Barnett shale from various companies after XTO studied the play for 2 years (OGJ Online, Feb. 24, 2004).
"XTO looks for opportunities to apply the most sophisticated exploitation techniques; that is their bailiwick. To me, that would be more likely to have something to do with horizontal application than it would [with vertical drilling], where the template is very well-known in the core area," Meyer said.
Using information compiled from various publicly traded companies, Simmons & Co. has calculated an average 20% internal rate of return (IRR) for Barnett shale producers if gas prices average $3.50/Mcf at the Henry Hub.
"We are showing a 12% IRR at $3/Mcf, which is pretty robust compared with some other areas," Meyer said.
Three biggest operators
Devon is the biggest leaseholder and the most active driller in the Barnett shale. As of late February, Devon had 13 rigs running in the play.
The company considers eastern Wise and western Denton counties to be a low-risk production base, containing 120,000 acres of Devon's total Barnett shale 550,000 net acres.
In 2004, Devon plans to drill 98 vertical wells and 42 horizontal wells in the play's core (Fig. 1). Already, the company has more than 1,600 wells producing a net 575 MMcfed. Devon operates all the wells, having an average 90% working interest.
Devon's companywide production target for 2004 is 256-261 million boe of oil and gas, of which 15% is expected to come from the Fort Worth basin, of which all of Devon's production is from the Barnett shale.
Another producer, Houston-based Burlington Resources Inc., conducted pilot drilling in the play and then entered the Barnett trend in a big way during third quarter 2002 by acquiring assets in the shale from a small, private company.
The acquisition provided 77 existing Barnett shale wells along with 21,000 largely undrilled net acres in the heart of the trend.
The company's intensive drilling program added 163 wells through Dec. 31, 2003. At its drilling peak last year, Burlington had 9 rigs running in the Barnett shale and was the trend's second-most-active driller behind Devon.
Last year, Burlington's total gas production was 2.67 bcfed. The company expects to increase overall production this year at the upper end of its standing average annual growth goal of 3-8%.
Burlington's Barnett shale production alone averaged 57 MMcfed last year, climbing to 65 MMcfed at yearend. This year's target is 75 MMcfed, which Burlington plans to achieve by drilling another 110 wells in the core area.
Barry Winstead, vice-president of Burlington's MidContinent division, characterizes the trend "as an extremely rich resource area. We've since added more acreage, building our current inventory to 28,000 net acres, with 2.7 tcfe of gross resources in place under those leases. Obviously, not all of that is recoverable."
Burlington's overall exploration and production budget this year is $1.5 billion, of which $70 million is for development drilling in the Barnett shale. That translates into five rigs running in the area all year.
"What Burlington tries to do on a repeatable basis is find those areas where we can enter and be different, establishing what we call 'basin excellence'. In other words, we try to capitalize on our core skills—operating large-scale, multiyear programs in geologically challenged areas."
The Barnett trend fits with these skills and has bolstered Burlington's production and income, said Winstead.
Burlington Resources Inc. Vice-Pres., Midcontinent, Barry Winstead
"It is a great place for us to apply our internal program drilling expertise. As far as the economics for Burlington, it is certainly profitable," Winstead said. "That's without even mentioning the strong gas prices over the last 18 months, which has made it even more attractive."
Although Burlington is the play's second most active driller, a privately held Dallas-based company currently is the play's second biggest producer. Chief Oil & Gas LLC Pres. Trevor Rees-Jones believes that horizontal wells will yield better economics than the traditional vertical wells. So far, Chief has drilled 12 horizontal wells.
Depending upon the horizontal drilling success rates, Chief could drill 60-70 wells in the shale this year, of which half would be horizontal wells.
"There is a learning curve with anything you do in oil and gas. There continues to be a learning curve out here," Rees-Jones said of the Barnett shale.
Chief operates entirely in the Fort Worth basin. In February, its production was 95 MMcfd, and the company's goal is 120 MMcfd by Dec. 31.
"We primarily are staying in the core for production growth for now. We just don't know yet whether it is going to work in the expansion area or not," Rees-Jones said. Chief has 70,000 Barnett shale acres under lease, of which half is in the core and half is in the noncore.
"We currently operate over 200 wells in the field," he said. "The overall challenge is to figure out how to get a greater percentage of gas in place out of this reservoir."
Expanding the core
Brian J. Jennings, Devon senior vice-president of finance and corporate development, noted that Devon has 430,000 noncore acres in western Wise, Jefferson, and eastern Parker counties. Effective Mar. 31, he becomes Devon's chief financial officer.
Early this year, all of Devon's drilling rigs were focused on the core area, although Devon is actively pushing the limits of the field.
Last year, Devon drilled 18 horizontal wells in the noncore area, where it plans to drill 52 horizontal wells this year. The horizontal spacing is 160 acres/well, which means that one horizontal well can accomplish what 2-3 vertical wells would accomplish (OGJ, Jan. 19, 2004, p.58).
Burlington, meanwhile, was completing two horizontal wells and drilling a third, all in the core area, in late February. An initial horizontal drilling assessment will involve six wells.
"We are evaluating the various completion techniques and monitoring offset wells during the hydraulic fracturing to assess the optimum design, so we're doing quite a bit of science on these initial horizontal wells. It's too early to speculate on the outcome," Winstead said.
Burlington remains focused on the core area in Wise and Denton counties, but Winstead said the company is "also going to take a broader look at the Barnett shale in the future.
"We are looking farther out in the adjacent counties, and we think there are some other basins that have the maturity, proper depth, and rock properties to also make them attractive Barnett shale plays."
Although he declined to elaborate because of competitive reasons, he said Burlington is closely watching "the tremendous amount of activity" in the adjacent noncore Johnson and Hood counties. "Right now, the cost of entry is quite high, and the results are somewhat marginal."
Play economics
Jennings said that Devon "likes the economics here. When you are selling gas into a market that you can see from your drilling rigs, we feel pretty good about the competitive advantage of that gas in the basin. We feel that we can be very active here for years to come."
Devon processes the raw gas stream at its Bridgeport plant (OGJ Online, Dec. 7, 2000), while dry gas, stripped of natural gas liquids and impurities, goes directly into Devon's own pipelines.
Faced with rising steel prices and other escalating business costs, Jennings said that Devon's position as the largest operator in the Barnett shale helps create efficiencies of scale.
"We are gaining experience with every well we drill and every well we frac. Over time, experience leads to lower costs and more-efficient operations. If you want to reduce cost or control costs, creating efficiency is a very, very beneficial way," Jennings said.
The economics of the play for Devon are such that it can generate after-tax returns with percentages in the midteens at gas prices of $2.75-3/Mcf in the Fort Worth basin, he said.
"In the basin, we think we can make money at that level. Certainly, there are wells that do much better. But on average as we expand the play and battle these rising costs, we think we still are very comfortable, and we can generate returns in this price environment. There are very few opportunities, we think, in this country to generate returns if prices were to fall into the $2-2.50/Mcf range."
Devon's 2004 total upstream budget is about $2.2 billion, of which $300 million is allocated for the Barnett shale.
"A lot will be driven by the activity outside the core area. We are actively working with industry to expand the playU. To the extent that our drilling results, particularly horizontal drilling, lead to success in these noncore areas, then I can see a scenario where we increase spending," Jennings said.
Well economics
Burlington has reduced its average cost to drill and complete a Barnett vertical well to $650,000 from its 2002 costs of $975,000/well. Meanwhile, the company estimates the industry average cost for a vertical well in the shale at $750,000.
"We've aggressively worked on these well costs," Winstead said. "A significant part of our success is in the form of lower completion costs. That is a big piece of the total drilling cost. We've also benefited from global procurement of services in the area. And our high activity level has helped—when you keep that many rigs running continuously, you can really optimize your expenses."
Burlington's $650,000 vertical well cost breaks down into $242,000 for completion, $360,000 for drilling, and $48,000 for facilities to equip the well and service it.
Winstead said Burlington also benchmarked operating costs for industry in the Barnett, and that the company is "right in line. Our total operating costs are 25¢/Mcfe right now, about where the group is running, and that includes both direct and indirect costs."
Burlington's companywide production, processing, and administrative costs were 68¢/Mcfe in 2003, so the shale easily complies with the company's low-cost emphasis.
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The economics of the play for Burlington are such that investments in the shale look attractive at Henry Hub natural gas prices of $3/Mcf and higher.
Regarding Devon's shale operating economics, Jennings said the typical Barnett shale well costs Devon $700,000/completion, which is about a 30% reduction from the costs of mid-2001.
"We are getting close to 1 bcf/well in reserves. That is very attractive finding and development costs when you spend roughly $700,000 to get 1 bcf of gas," he said.
Devon's typical Barnett shale well experiences a decline from its initial production rate, but then the well produces for 6-10 years.
"On a finding and development basis, it's one of our most attractive regions.
Devon is counting on horizontal drilling for significant efficiency improvements and ultimately cost savings.
"It enables us to recover gas by drilling fewer wells, which makes the economics much more beneficial," Jennings said. "We are out there every day trying to be a more efficient operator—that is a struggle we have every day in terms of trying to preserve profits for shareholders." ogfj
Devon Energy Corp.
Senior Vice-Pres., Finance,
Brian J. Jennings
"When you are selling gas into a market that you can see from your drilling rigs, we feel pretty good about the competitive advantage of that gas in the basin. We feel that we can be very active here for years to come."
A Barnett shale primer
The Barnett shale is an unconventional natural gas play that requires special stimulation techniques designed to improve flow from shale reservoirs with low permeability (the ability of a fluid to flow through a porous medium such as subsurface rock formations). Although it represents a long-identified, vast natural gas resource spread over several counties in north central Texas, tapping the huge potential of the Barnett shale has become economic only in recent years with the application of massive hydraulic fracturing, or frac, jobs to stimulate gas to flow from the tightly layered subsurface shale formations. A frac job entails the pumping of water or sand and/or gelled fluids downhole to widen the natural fractures or create new fractures in tightly consolidated subsurface rock formations. The fractures are propped open with different materials called proppants. Frac jobs for Barnett shales can entail pumping several million pounds of sand downhole along with some costly gelled fluids to convey those volumes. But a Barnett shale well is worth all the effort and expense to the operators; dry hole risk is all but nonexistent, and the wells produce sizeable volumes of natural gas at steady rates for a long time. Light sand fracs, new approaches in frac jobs in the late 1990s, reduced costs by 20% by using greater volumes of water and much smaller amounts of sand. Meanwhile, advances in subsurface imaging technology are bringing the Barnett reservoirs into clearer focus; this, coupled with improved drilling and well-completion techniques, is helping operators discover new efficiencies and cost savings in a big-potential, low-risk play.
