Operators below the rich-gas line are not crying over dry Eagle Ford shale gas. Instead, they are counting silver linings behind other opportunistic pay zones.
Some 4,000 Eagle Ford shale aficionados gathered in San Antonio, Texas, in October 2011 for Hart Energy’s Developing Unconventional Gas Eagle Ford conference to talk about one of the world’s most prominent shale gas plays. But notably, three operators took the stage to talk about other hydrocarbon zones in South Texas – because the economics are better than the Eagle Ford.
Better than the dry-gas window, at least, where these operators hold the majority of their interests south of the more-favored rich gas/condensate and oil zones of the Eagle Ford shale. With natural gas prices remaining depressed, producers have focused their attention and public hype on Eagle Ford zones with liquids, which deliver higher rates of return.
And yet none of these dry-zone operators seems to lament what might have been. In fact, the leaders of Swift Energy, Laredo Energy, and Escondido Resources II are excited about the potential value of the resources underlying their positions, even declaring that the economics are as good as Eagle Ford sweet spots.
Bruce Vincent, president of Swift and former chairman of the Independent Petroleum Association of America (IPAA), is enthusiastic about the Olmos formation, a low-permeability sandstone that lies above the Eagle Ford. The Houston-based company currently holds about 44,000 net acres prospective for the Olmos.
“We drilled a horizontal well in the Olmos prior to drilling our first Eagle Ford well, and surprise, the economics were terrific – in a lot of ways similar to what we’re finding in the liquids-rich Eagle Ford area,” he said.
The key word is horizontal. Swift Energy has been drilling vertical wells into the Olmos here for 20 years, but it is the introduction of hydraulic fracturing techniques combined with horizontal drilling – introduced to this scrubbrush region by Eagle Ford operators – that has made South Texas a cornucopia of revived multizone pays.
Within the Olmos trend, Swift uses two economic models – one with free-flowing condensate and the other with high-Btu gas. “The gas generally runs 1,250 to 1,300 Btus, so you strip out a lot of liquids, which really improves the economics,” Vincent said.
Swift estimates it has 275 Olmos locations on 160-acre spacing. It expects a resource potential of 6 Bcf and costs of US $8.5 million to $9 million per well with a 1,830-m (6,000-ft) lateral.
Beyond the Eagle Ford
Laredo Energy, a privately held Houston-based company with backing from EnCap Investments and Avista Capital Partners in its fourth iteration, has drilled more than 400 wells in Webb and Zapata counties over the years. Until three years ago, however, none of the team had ever drilled a horizontal well, according to Laredo President and CEO Glenn Hart. “That’s all we do now,” Hart said.
Laredo IV was built to focus on the Escondido formation. With previous iterations targeting the Lobo trend, in 2007 the company turned its attention to the shallower Escondido in northern Webb County. Those plans, however, were soon sidetracked. “We didn’t go looking for a shale play, but very much to our surprise, a shale play wandered into the neighborhood,” he said.
Beating the land rush, Laredo amassed a 134,000-gross-acre (78,000 net) position prospective for the Eagle Ford 40 km (25 miles) west and on strike with Petrohawk Energy Corp.’s original discovery and began proving up the perimeter. But a funny thing happened on the way to the Eagle Ford, he said. “We were finding a tremendous amount of hydrocarbons in these wells.”
When several wells showed other pay zones, Laredo skidded the rig over and has now drilled an additional seven horizontal wells into the Escondido and Olmos formations. The results of the Escondido wells have been remarkable, Hart noted, with some showing sustained rates of 10 MMcf/d to 12 MMcf/d from 1,524-m (5,000-ft) laterals.
Laredo now is drilling Escondido wells to preserve the deeper Eagle Ford rights for when gas prices improve.
“In the short term, the economics of the shallower non-Eagle Ford wells are better,” he said. With two rigs running, “the biggest part of our 2012 budget will be drilling non-Eagle Ford horizons. With cheaper costs (to drill into shallower zones) and almost as big of reserves, it’s clearly the direction we should be going short term,” Hart said.
Not to be ignored are other zones with significant pay, including Wilcox, San Miguel, Austin Chalk, and the Pearsall shale. Take the Austin Chalk, a dry-gas trend oft considered 1990s news. Down in South Texas, core samples of the chalk look the same as the Eagle Ford – black rock with flecks of limestone. As Laredo drilled its first Eagle Ford wells, Hart’s geologists repeatedly insisted he look at the Austin Chalk logs.
“We’ve been flabbergasted at the performance of the two additional stages in the Austin Chalk,” he said. “It adds about 1.5 Bcf incrementally for a very low cost.”
According to Hart, the technique is one method of improving economics in the dry-gas Eagle Ford window.
Laredo followed on with two additional Chalk horizontals. “So far, it looks like the production from the Austin Chalk wells is every bit as good as the Eagle Ford,” Hart said.
Combined with the Eagle Ford, the resource base of the two, including the Austin Chalk, on Laredo’s acreage is huge, he said. “We’re talking 5,000 to 6,000 locations with 15 Tcf recoverable.”
Bill Deupree, president and chief executive of Escondido Resources II, says the Midland, Texas-based private company is at a crossroads. With 30,000 acres prospective for the Eagle Ford shale and another 60,000 in the shallow reservoirs of the Olmos and Escondido, it is trying to decide which way it should turn its capex.
“Do we follow the pack and keep drilling Eagle Ford wells, or go a different direction and employ the new technology gained from drilling these Eagle Ford wells to our old friends the Olmos and Escondido?” he asked.
Deupree calls the Olmos and Escondido reservoirs the “hidden reserves” of South Texas. The company focused its leasing efforts on multipay opportunities in Webb, LaSalle, and McMullen counties, which pushed it into the dry zone of the Eagle Ford. It now holds 60,000 acres there with a choice of targets.
Escondido Resources drilled its first Escondido horizontal well in 2009, immediately following its first Eagle Ford well, and has now drilled 25 horizontal wells: 16 in the Escondido, five in the Olmos, and four in the Eagle Ford.
Escondido I – sold in 2007 for $250 million – drilled 190 vertical Escondido and Olmos wells with a peak production of 25 MMcf/d, “which we considered phenomenal at the time,” Deupree said. However, “Our last three wells in Escondido II will produce the same amount from the exact same reservoirs.”
In January 2011, the company drilled its best well ever, an Escondido well with a 1,524-m (5,000-ft) lateral that had an initial production (IP) of 12 MMcf/d. Cumulative production is 5 Bcf in five months.
And the Escondido and Olmos are both rich gas, about 1,130 Btu. “We get quite an uptick from processing on those wells,” Deupree said. With 15 wells completed into the Escondido, the company averaged an IP of 7 MMcf/d with 4.8 Bcf estimated ultimate recovery.
“These results have exceeded our expectations,” Deupree said. “The economics of drilling in the Escondido and Olmos formations are excellent even in the current gas price environment and are comparable – if not better – than the rich-gas Eagle Ford trend.”
Escondido’s focus in 2012 will be on the Escondido and Olmos reservoirs, with about 85% of its $150 million to $200 million budget directed there. All of its efforts will be horizontal. “Overall, our results in the Eagle Ford have been good, but our results in the Escondido and Olmos have been better. We’re not going to totally exclude the Eagle Ford, but we need gas prices to improve a lot of the acreage in the dry gas portion of the trend.”
Escondido II now sports more than 600 drilling locations across multiple objectives. Deupree estimates the company holds 2.5 Tcf or more of gross resource potential in South Texas.
“We are applying new technology to an old, established, producing area,” he said. “We are now targeting these same reservoirs with horizontal drilling and large slickwater fracs and have been having excellent results.”
This article was modified from the original from the December 2011 issue of Oil and Gas Investor and has been reprinted with permission.