The sprawling Eagle Ford Shale has a lot going for it—great geology, close access to excellent midstream infrastructure and downstream markets, supportive landowners, and a favorable regulatory environment. But challenges lie ahead as the big unconventional play continues to evolve.

The Eagle Ford Shale spreads across 644 km (400 miles) from the Mexican border to eastern Texas. Since the first well was drilled by Petrohawk in 2008, activity has exploded in the area and shows no signs of slowing. To keep up, though, companies must continue to improve efficiency, attract skilled personnel and ensure they have the supplies and infrastructure needed to produce the play.

Progress and potential

Three industry experts addressed the play’s potential and challenges during a wide-ranging roundtable discussion of the play at Hart Energy’s fifth annual DUG Eagle Ford Conference & Exhibition in San Antonio in September.

Josh Weber, senior vice president, commercial and business development for Howard Midstream Energy Partners LLC; Tim Murray, managing director for GSO Capital Partners LP; and Phil Mezey, executive vice president, Southcross Energy Partners LP; started off by recounting their first exposure to the Eagle Ford following its late-2008 discovery.

Murray recalled that for him the Eagle Ford early on provoked “bittersweet memories of the Austin Chalk,” an earlier Texas play that spurred a lot of industry excitement in the 1980s and 1990s before falling out of favor.

“That was a pretty wild pony,” he said of the Austin Chalk. “You had some very high rates that fell off very quickly. Mix that with volatile oil prices, and it made for a wild ride.”

However, he added the Eagle Ford has proved to be more akin to the Niobrara, “an established basin where there are other producing horizons that are a little tired, and it has brought in new excitement.”

Considering the Eagle Ford from a financial perspective, Murray said that “the calculus has changed” for the play following the initial “land grab” for leases, followed now by producers’ establishment of long-term, capital-intensive development plans. “It’s been an interesting five to six years,” he said.

Mezey said he saw the Eagle Ford close up from its start. He told how the firm he was with at the time—chasing the Austin Chalk—had acreage adjacent to the Petrohawk discovery in the fall of 2008 that started the Eagle Ford on its way. “We were already having problems getting oil out, and we realized right away there were going to be some constraints” on midstream capacity. He was involved in building an initial Eagle Ford crude-gathering system that was sold to NuStar Energy LP. The Petrohawk well was good, but as horizontal wells got longer and fracking programs became bigger, “every well we saw was getting better and better.”

The panelists agreed that all of those positives for the Eagle Ford have combined to make it a world-class play that now produces some 1.5 MMbbl/d.

“It has been a great place to work,” Mezey said. “We know what the rules are, and they are consistent.” That has been a contrast to plays in other states where regulation has been constraining and public support weak.

The panel also agreed that the best may be yet to come for the Eagle Ford. Weber pointed to the growing market in nearby Mexico, a promising market that now looks even better with that nation’s recent revamping of its energy law.

That demand could help open up the dry gas-prone southern side of the formation that has seen little activity in recent years due to low gas prices. The central and northern portions of the play, typically producing more lucrative NGL-rich natural gas and crude oil, have been the scene of most Eagle Ford drilling. However, those wells typically have good associated gas production.

Development of new midstream infrastructure on the Texas Coast, in particular improvements to the Houston Ship Channel and new processing, storage and docks at Freeport and Corpus Christi, will be a plus for the growing waterborne exports. The light liquids and rich gas typical of Eagle Ford wells feed into the growing export market for NGLs and the promise of condensate exports. New condensate splitter capacity is another plus for the play, the panelists agreed.

Mezey discussed the variables that could make the Eagle Ford export market even stronger, including Mexican and Caribbean demand and the prospect of new Asian customers following completion of the Panama Canal expansion.

Exports are the key to the Eagle Ford’s future progress, Murray said. If current strict limits on crude exports remain in place, the play “could hit a brick wall a year from now with all this light crude.” Gulf Coast refineries have been geared to run heavy and sour imports, and processing the Eagle Ford’s light, sweet crude and condensate isn’t economic. That production should be allowed to seek its own market, he added.

Collaboration necessary

Growth in the Eagle Ford over the past several years has been incredible. However, competition for people, products and technology in U.S. unconventional plays is intensifying, and other basins are competing for those resources in the Eagle Ford.

“If we don’t collaborate and optimize our productivity on a per-well basis, these resources will be allocated to less mature basins. Mature basins such as the Eagle Ford must continue to focus on productivity and efficiency in wells to stay out in front,” said Tammi Morytko, vice president, southern U.S. geomarket, Baker Hughes.

“From a service company perspective, we believe the answer is collaboration at the well site and during the planning stage, which is the key to growth and retention of economics for our producers,” she added.

Fit-for-purpose optimization and real-time monitoring of stage effectiveness are factors that can be delivered in many processes and technologies. “I think we can agree it is time for fewer handoffs, more science, more collaboration and superior economic outcomes as a result,” she continued.

Recent trends in large completions, frack volumes and logistical challenges coupled with inflation are causing completion costs to increase. The cost is expected to rise by more than 25% during the next year. On a macro basis, productivity or dollars per boe is flat to declining due to steep decline curves and ineffective fracturing results, she explained.

“A variety of industry reports acknowledge that 60% of frack stages are ineffective. These ineffective stages equate to more than $40 billion of annual spend. Improving the performance of those ineffective fracks will result in significant increase in production as well as dollars/boe. That’s what really matters,” she emphasized.

Challenges facing industry

With ever-increasing demand for horizontal completion and production capacity, the industry faces challenges in finding enough people, creating enough infrastructure and producing enough sand and water.

“It is challenging to find qualified people. Land drilling has seen a 400% increase in volume and activity for logistics since 2010. Keeping up with supply and moving supply around is a real challenge. Sand and water are continual constraints from the mines to the wellbore. Horizontal frack stages are estimated to increase by 173% from 2010 through 2016. We are certainly constrained to continue to do business as usual,” Morytko said.

“Continued growth in rig activity is straining both the service and E&P companies. Rig counts are not growing out of control; however, the intensity, size and length of horizontal completions are driving twice the consumption of people, horsepower and supply. The Permian growth is affecting the basins due to its pull on personnel and supply,” she continued.

“We’ll see constraints not only growing in the Eagle Ford but other basins unless we develop more infrastructure and get creative to address the personnel, equipment and supply issues that are required to recover these hydrocarbons,” she emphasized.

Meeting challenges

The U.S. unconventional success has been driven by a great focus on efficiency. The current market was built on a step-change in efficiency improvement, mainly to drilling optimization. However, the rate of change is slowing, and incremental improvements will have much smaller economic benefits than those previously realized.

“It’s easy for operators to get trapped in a cost-reduction mindset vs. focusing on the unrealized productivity gains. We believe we are at a critical inflection point for operating companies. As service companies, we must stand up and help with this change,” Morytko explained.

“We feel we must combine our successful approach to efficiency gains with a focus on improved productivity. Our productive improvement on a per-well basis will come from unique applications of completion and reservoir technologies,” she continued.

That brings the emphasis back to collaboration. Improving productivity on a per-well basis will take a collaborative effort as well as service companies applying expertise. “You don’t have to look far to see the incredible advancements in reservoir tools and completion technology. There are tools that allow stage fracture optimization.

“There are tools that collaborate with several diagnostic technologies to tell the whole story and devise a much more fit-for-purpose plan of attack to recover those hydrocarbons. True system-based applications focus on the risk-reward economics aligned around initial production and ultimate recovery,” she said.

“It is all about intelligence and collaboration to yield the right productivity signal for our customers. It is what they need to demand in this environment. There is so much we can offer from collaborating from the start of the project and throughout the life of the recovery process. We’ve only begun to scratch the surface of what is possible. Together, we’ll be stronger and create new beginnings for greater profitability for all,” Morytko concluded. “We have to think differently to create new possibilities.”

Enhanced completions boost EURs

Pioneer Natural Resources was working South Texas for years before the Eagle Ford emerged. Pioneer was busy drilling Edwards Trend gas wells on a nice leasehold position that later turned out to be smack in the heart of the Eagle Ford play.

“It’s been a phenomenal play for us,” said Timothy L. Dove, Pioneer’s president and COO. “In essence, when it comes to the Eagle Ford Shale, we had zero-cost basis to enter the trend.”

Pioneer concentrates its efforts in the Eagle Ford’s condensate window, where it produces liquids-rich gas at high pressures and high volumes. Today the operator makes 135,000 boe/d from its 215,000 gross acres, about 68% liquids. It’s a stunning growth trajectory from the 4,000 boe/d it produced in 2010.

In 2012, Pioneer moved from the exploration phase of its Eagle Ford assets to field optimization. “We are in continuous development, continuous improvement mode,” Dove said. “Now we’re in the process of optimizing our well spacing and completion designs. We are making sure that we are reaching out and touching all of that rock volume that we need to stimulate for maximum production.”

Today Pioneer is drilling 100% of its Eagle Ford wells on multiwell pads. Last year, it implemented a two-string design, which saves $750,000 to $1 million in drilling cost per well vs. a three-string design. Additionally, between 2011 and the first half of 2014, it dropped its cost-per-foot from $265 to $201. During the same period, total distance per day increased from 151 m to 223 m (496 ft to 730 ft).

Another area of effort is determining effective downspacing for the reservoir. “Understanding stimulated rock volume is crucial,” Dove said. “We want to get close to that point where we have constructive interference.” Among the technologies that Pioneer uses to hone its well spacing are microseismic, 3-D seismic, tracers, geochemistry and frack modeling. Initially, Pioneer located its wells 300 m (1,000 ft) apart. Now it has downspaced in pilot areas to between 53 m and 91 m (175 ft and 300 ft) apart, including staggered laterals in upper targets.

On completions, Pioneer has been focused on optimizing its treatments. This ranges from pumping more bbl/min per perf cluster to reducing the spacing between clusters. The volume of proppant pumped per foot is also increasing. Today the typical Pioneer well features 21 stages spaced 15 m (50 ft) apart, pumped at 16 bbl/min with 1,200 lb of proppant per foot.

The results have been stunning: In some areas, Pioneer has realized a 20% to 30% EUR increase with minimal increase in drilling and completion costs. “These completions make sense and make money,” Dove said. “We have seen quite outstanding results so far.”

Increased production

More drilling activity and better drilling efficiency have led to significant crude oil production increases in the Eagle Ford, according to a release from the Energy Information Administration (EIA). These increases have occurred despite the region's relatively high well decline rates. By using new recovery techniques to offset natural declines, companies in the region could further increase production.

Horizontal drilling combined with an increasing number of hydraulic fracturing stages in tight formations like the Eagle Ford typically enhance IP rates when compared to past results, according to the release. These higher IP rates are often accompanied by initially larger decline rates before gradually leveling off to a consistent level of decline for the remaining years of the well’s life.

IP rates have steadily increased since 2009, and first-year decline rates in the Eagle Ford have ranged between 60% and 70%, according to the EIA. Decline rates during the second year of production have risen from 30% for wells drilled in 2009 to nearly 50% for wells drilled in 2011 and 2012. Since 2013, many producers have been using more proppant when fracturing new wells, which appears to have increased IP rates but was followed by a steeper drop in production, the EIA said in the release.