Come And Take It

The first shots in the Texas Revolution popped sporadically across the fog-shrouded live oak bluffs along the Guadalupe River near Gonzales, Texas, at dawn on October 2, 1835, after Mexican soldiers arrived to reclaim a small cannon from Texas colonists. The Texians surreptitiously buried the weapon and unfurled a hastily assembled flag with one lone black star and an image of the diminutive cannon underlain with the response that began the revolution: “Come and Take It.”

Today, salvoes from a new revolution are under way as the Eagle Ford shale tempts oil and gas operators to come and take it, indeed. The play has reached full development in a core zone that traces the same revolution-era rolling countryside south and west of Gonzales that is now rural ranch- and farmland with drilling rigs, retention reservoirs, RV parks and trucks—hundreds of rolling trucks—interspersed among a live oak prairie populated by the descendants of German, Czech and Hispanic immigrants, many tracing roots back 150 years.

Like the results from the original Texas revolution 171 years ago, the Eagle Ford has come of age as operators employ a systems-engineering approach to harvesting the largest and fastest-growing in situ oil shale play in North America.

Previously, oil and gas development was the province of wildcatters and sharp-eyed geologists extending the frontier one well at a time via a three-dimensional journey through the earth’s crust. In contrast, today’s Eagle Ford presents the largest domestic effort to systematically develop a highly varied onshore hydrocarbon reservoir across a geographic landscape 250 miles long, using pad drilling, synergistic completion techniques in parallel horizontal laterals, and the simultaneous build-out of midstream infrastructure across thousands of wells. That process mimics a manufacturing model and seeks efficiency through repeatability and continuous improvement over a decade-long development program.

As the Eagle Ford transitions into the resource harvest phase of the unconventional cycle, large-scale development programs, several started from scratch less than three years ago, are as intricately detailed across multiple upstream and midstream disciplines as any modern military campaign. In a sense, it has been a matter of creating a fully integrated industrial complex in an isolated rural area, with global repercussions.

Oil production from the Eagle Ford, estimated at 873,000 barrels of oil equivalent per day (BOE/d) in May 2013, according to Credit Suisse, plus 3.83 billion cubic feet of gas per day, is part of the astonishing reversal in previously declining U.S. crude output that promises to reshape the global energy industry.

The Eagle Ford is a co-leader (with the Bakken shale) in this trend and serves as the most active shale play in the U.S. with 230 rigs, according to Baker Hughes Inc. While rig counts are down 10% from their second-quarter 2012 peak, the new revolution in Texas enables the industry to drill more wells with fewer rigs—an estimated 4,259 wells in 2013, according to a PacWest Consulting Partners forecast.

This is turning drilling efficiency into lower well costs even as the first steps in evolving completions technology, coupled with downspacing to 80 acres or less, boost estimated ultimate recovery rates (EURs) into a range of 300,000 to 600,000 BOE versus an average 206,000 BOE in early 2012, according to a Society of Petroleum Engineers International study of more than 1,000 wells.

But today’s Eagle Ford story—and the evolving story in the domestic oil patch—is not just about headline-grabbing open chokes and “monster wells.” Rather, it is about reservoir management and the ability to build a just-in-time midstream infrastructure to stay one step ahead of quickly moving new technology rigs turning wells at ever faster rates and the thundering, rugged fleet of pressure-pumping units following close behind.

It seems the shots fired in today’s Texas revolution now occur as stage perforations a mile and a half deep at 250-foot intervals along horizontal wellbores that stretch 5,000 feet, or more, beneath the historic South Texas countryside.

Since the generally accepted Petrohawk STS-241 #1H commercial discovery in October 2008, the Eagle Ford shale has been land-grabbed, delineated, evaluated and optimized across 10 Texas counties south and east of San Antonio as part of the great unconventional development cycle unfolding in multiple North American basins. But the cycle unfolded faster in the Eagle Ford for a variety of reasons, including existing midstream infrastructure, proximity to the Gulf Coast petrochemical complex, a business-friendly regulatory environment, and a population comfortable with oil and gas development.

Larger, well-capitalized oil and gas firms played an early role, unlike in many unconventional plays that start with smaller players. Crucially, the Eagle Ford was recognized as an oil play just as the industry pirouetted to a liquids-rich mantra in 2010. The Eagle Ford was the right answer at the right time, allowing operators to make a quick transition from dry gas.

“Many operators already owned great oil acreage spanning thousands of acres, usually on three-year leases, which prompted the industry to move quickly,” says Lance Robertson, Marathon Oil Corp.’s Eagle Ford vice president. “Plus, the Eagle Ford was also unique in that it was just mature enough at the time that you saw lots of joint ventures placed early as a source of funding outside of conventional debt or equity, and that allowed acceleration.”

Only two unconventional plays have exceeded 200 active rigs. It took the Bakken six years to get there from an average 50 rigs active in early 2007. The Eagle Ford covered the same ground in two years.

“The combination of several things—the right players, the right historical experience, pre-existing well log data, 3-D seismic and one that is often overlooked—a proximity to existing infrastructure for oil and gas pipelines—was there,” Robertson says about the early Eagle Ford. “You could drill a well and you knew from the earliest days that you could export production to market and generate cash flow.”

Demand for services soon exceeded supply, costs escalated and shortages developed as operators scrambled to capture acreage and delineate sweet spots. The new-fangled oil shale play had turned into an old-fashioned boom. According to PacWest Consulting Partners, pressure-pumping capacity in the Eagle Ford nearly doubled from 1.8 million units of hydraulic horsepower (HHP) in third-quarter 2011 to 3.4 million HHP in second-quarter 2013.

Today, the short supply in equipment and people has morphed into an oversupplied services market as the Eagle Ford settles into the resource harvest phase in its core, though acreage capture continues among large landholders outside the Karnes, DeWitt, Gonzales, and LaSalle counties axis.

“The proximity of the Eagle Ford to other long-time basins means there is a ton of service capacity in the market,” says Chris Robart, principal with PacWest Consulting Partners LP. “No one is having any problems contracting frac companies. There is a little bit of downward pressure on new tenders, but pricing is at, or near, the bottom.” When it comes to services, it is a buyers’ market.

“In terms of our daily discussions, we’re talking about efficiencies, optimization, lateral length, proppant mixes, proppant concentrations, how fast can we drill wells,” says Tony Sanchez, chief executive of Houston-based Sanchez Energy Corp. “The Eagle Ford has clearly transitioned into the harvest phase of the maturity cycle, which is now the fun part. When you are out there battling with people who are willing to pay $5,000 per acre, it is not a lot of fun, because you see the dollars going out the door.”

Carrizo Oil & Gas Inc.’s Andy Agosto, vice president for business development, agrees. “From a geologic standpoint, the industry has fully delineated the Eagle Ford,” Agosto says. “The land rush is done. We are in the process now of doing trades with some of the offset operators, which is sort of the natural evolution in shale plays where everybody rationalizes their acreage positions. For Carrizo, we are definitely in the harvest mode in LaSalle County.”

If operator plans unfold as stated, oil and gas drilling and development spending in 2013 will top $28 billion, including $2.2 billion in rig costs and another $5.5 billion in well-stimulation costs.

The Eagle Ford is the largest—and the first—unconventional play involving widespread oil and liquids extraction from a shale reservoir. As such, it serves as a model for how the resource harvest phase in unconventional oil—a transformative event in modern oil and gas—will evolve over the next half decade as the focus on oil in shales extends to the Permian Basin Wolfcamp in Texas and Colorado’s Niobrara shale. In contrast, the Bakken shale—the penultimate North American tight-oil play—is unique in that it involves extracting oil from sandstone inter-bedded between two shale layers rather than oil directly from shale.

So what the Eagle Ford looks like now as the transition to resource harvest unfolds in 2013 is a starting point for what other tight-oil plays may look like in the future.

Wells, not rigs

“One of the things we are trying to do is get away from rig count and talk more about well count,” says J.D. (Joey) Hall, senior vice president for South Texas operations at Pioneer Natural Resources Co. “We drilled 134 wells last year with 12 rigs. We are going to drill a similar number of wells in 2013, only with 10 rigs. We are developing efficiencies that help us progress more quickly with fewer resources.”

Hall cites a 34% cycle-time improvement in Pioneer wells over an 18-month period dating back to second-quarter 2011. “Some of that can be attributed to the fact we were ramping up on pad drilling, but also just the fact that we’re making optimizations and improvements in our normal cycle time even for single wells. We’ve been drilling so many wells for so long that we are incorporating lessons learned from our previous wells and just getting better at drilling them.”

Those efficiencies come in many ways. Pioneer , which has drilled more than 300 wells in the Eagle Ford since 2010, is transitioning to batch drilling in 2013, a process in which a rig bores and sets casing in the surface and intermediate sections for each well on a two- to six-well pad. Then the rig moves back down the line of wells on the pad, drilling and setting casing in the horizontal/production section.

Besides reducing nonproductive time involved in rig moves, which generates significant cost savings, batch drilling also captures efficiencies by reducing time spent switching between different fluid systems on the vertical versus the horizontal sections. Performance gains from better bits and modified bottomhole assemblies add to the savings from rig moves to lower well costs, which have dropped for Pioneer from $8- to $9 million on a generic Eagle Ford well in 2012 to $7- to $8 million in 2013.

Pioneer will drill 80% of its 135 wells on pads in 2013, compared to 45% at the end of 2012. Of the 10 rigs the company employs, eight feature walking systems and are capable of moving about in any direction on a pad site. But pad drilling is just one component on the drive to efficiency. Better drilling performance matters too. For Pioneer, it means targeting the lateral bore to the most productive zone of the larger Eagle Ford shale.

“We’ve put a significant effort to make sure we are staying in the target zone,” Hall says, noting the interplay between operation geologists who steer the lateral and drillers. “Being confident in knowing where you are, and where you are going, is one of the most underdiscussed and most underestimated gains in drilling resource-play wells. We keep track of what percentage of wells stay in zone. In 2012, and thus far in 2013, our wells are 96% in that target interval.”

The Marathon mobilization

The Eagle Ford shale witnessed one of the more remarkable mobilizations in modern oil and gas when Marathon Oil Co. went from a large-scale property purchase in 2011 with the $3.5-billion acquisition of Hilcorp Resource Holdings LP’s 141,000 net acres to 16 rigs active in roughly 120 days.

The company’s Eagle Ford effort began with fewer than 10 people doing the initial evaluation that culminated in several strategic property purchases in the Eagle Ford core. Marathon then assembled employees from its Bakken and Anadarko Basin business units and selectively targeted expertise among peers with substantial unconventional experience to launch a full-bore Eagle Ford effort. The company went immediately to pad drilling and simultaneous midstream infrastructure build out.

“The capital efficiency of pad development is so tangible and real that you want to get there quickly on the drilling side and the completion side,” Marathon’s Lance Robertson says. While efficiency gains in pad drilling are well documented, parallel improvement in completion efficiency is under way, even though the industry is earlier in the completion learning curve.

“Over the last two or three quarters, we’ve been able to change our initial production (IP) and 60-day cumulative rates up to 75% by moving to a combination of pad stimulation, where we can change the fundamental rock mechanics in situ, and combining that with changes in perforation cluster spacing, and fluid systems,” Robertson says. “Being able to do that in more than one well at a time is one of the key differentiators in well performance.”

Like gains in rig efficiency, batch completions capture time otherwise spent mobilizing equipment. Marathon further works with service providers to conduct routine maintenance at the well site to keep equipment working on location.

The company employs zipper fracs, a batch stimulation methodology that allows operators to complete single stages serially across parallel laterals. While one lateral undergoes a single-stage fracture stimulation, the operator runs wireline or perforates stages in adjacent laterals.

“We are now getting 30% more stages per month out of every crew than we were in the second quarter last year,” Robertson says. “We routinely get 110 stages a month out of a frac fleet. We would have been happy to get 75 or 80 stages a month in the second quarter last year.”

More importantly, zipper fracs work to increase fracture complexity and boost hydrocarbon recovery. Marathon’s Robertson compares it to filling a water balloon. A little water doesn’t do much. “But if you put a lot of water in it, you just have to poke it a little bit and it ruptures,” Robertson says.

“The Eagle Ford is a lot like that. If you pump a stimulation in the first well you put all that fluid in the rock and you pre-stress it, much like a balloon is pre-stressed. Then when you stimulate into it from the next well, the rock in the previous well breaks again. As you go down the line, and go back and forth, you are pre-stressing the rock and shattering it. You are changing the principal rock stresses in situ and we find that to be a powerful tool in making better wells.”

Marathon maximizes completions by running multiple logs and grouping perforation clusters to keep similar rock quality together, which minimizes disparaties in downhole pressure for proppant injection through individual perfora- tion clusters. Each fracture stage takes proppant more evenly and eliminates the variability in performance—inefficiency—between multiple stages that has characterized horizontal wells in other plays. It is part of a comprehensive philosophy to mix downspacing with completion efficiency to bring greater volumes of oil to market more quickly.

Marathon is currently running 15 rigs and four frac crews, down from 20 rigs last year, but will drill 50 more wells this year as it targets 300 locations in 2013 and exits the year with 80,000 BOE/d from its 200,000 net acres. The company employs project management software to coordinate all aspects of development , from the initial drilling permit to sales. The data is tagged to appropriate decision-making personnel, geo-referenced and put on maps so that it is possible to identify in advance, as just one example, when and where to install flow lines.

“Our goal from Day One is we should have flow lines built and meter kits installed before we ever frac the well, so we go from stimulation directly into flowback within days as soon as we mill the plugs,” Robertson says. That organizational acumen has Marathon turning new wells in frontier areas to sales in less than 60 days.

“As we move into facilities, keep this in mind,” Robertson says. “Of any of the shale developments in North America today, the fluids in the Eagle Ford are the most complex. It is a dry gas, a condensate, a volatile of oil, which is a very narrow band, and a black oil system. It is all four of those in one reservoir and sometimes within as little as 10 miles from transition to transition. You are producing oil wells, condensate wells and gas wells in some cases, so that makes midstream even more challenging, because you need a wet-gas outlet, a dry-gas outlet and you need stabilization for condensate and traditional black oil, which is more like the Permian.”

Extending the core

While industry focus is centered on the Karnes Trough and Sugarkane areas in the central Eagle Ford, the play provides multiple economic opportunities along its Nike Swoosh-like profile.

“We felt like the northern half of LaSalle County had the right mix of oil and gas,” Carrizo’s Andy Agosto says about the company’s 54,500 net acres southwest of the Eagle Ford core. “About 90% of our production is oil and not condensate. Our gas-to-oil ratio is high enough that we are still getting some additional reservoir energy that is helping our EURs. But we are not deep enough, or thermally mature enough, that we are producing much condensate, which receives significant price discounts. It’s generally volatile oil with an API gravity below 48 degrees.

“From an economic standpoint, with our lower well costs and a high percentage of premium-priced oil relative to gas and NGLs, we think we are in a sweet spot.”

With the agility smaller public independents use as a calling card, Carrizo began scouting the Eagle Ford in 2009 and initiated a leasing program in early 2010 during the height of the leasing scramble. Carrizo was making a corporate transition from dry gas to liquids. As core acreage costs spiraled higher, Carrizo looked for an area that had smaller lease bonuses, but still offered attractive economics.

“At the time we got in, it was less competitive in central LaSalle County than in the Karnes Trough area,” Agosto says. “We had the same logs to look at that our competitors did. We recognized that the Karnes Trough had additional thickness, additional oil in place. But we also knew that lease bonuses had increased significantly and the wells were going to cost more. These factors really pushed us to where we ended up in LaSalle.”

Carrizo entered the Eagle Ford as an experienced unconventional driller, based on its experience in the Barnett shale, where the firm earned a measure of fame for drilling 22 laterals on wellheads 10 feet apart on a single three-acre pad in an urban environment on the University of Texas at Arlington campus.

“We took learnings directly from the Barnett shale into the Eagle Ford,” Agosto says. “We actually moved a rig from the Barnett down into the Eagle Ford to drill our first well.”

Unlike the many companies that focused on acreage capture, Carrizo moved immediately to the same pad drilling/zipper frac techniques it used in the Barnett and quickly dropped drilling days from the low 20s to the mid-teens. On the completion side, the company’s dedicated frac crew is averaging six stages or more per day, which further reduces cycle time. The ability to reduce cycle time came from both internal and external sources.

“One thing we’ve seen in all the shale plays is once the land rush is done, these plays have tended to be fairly cooperative in terms of information exchange, which is different from my experience in the conventional business,” Agosto says.

Carrizo is running three rigs, including one newly built rig powered by natural gas, as it pursues a 60-gross-well drilling program on a $400-million budget in 2013. One advantage to LaSalle County is that the Eagle Ford is shallower than the core area to the northeast. “Even though our IPs and EURs are a little lower than those being reported in some other areas, people don’t always understand the profitability and value we are creating in our LaSalle County sweet spot,” Agosto says.

One hundred twenty miles to the northeast, Penn Virginia Corp. is extending the economic boundaries of the core Eagle Ford into Gonzales and Lavaca counties as it transitions its revenue base from natural gas to crude oil.

“We’ve been able to extend the play further, deeper, and expand the acreage through the transformative acquisition we did with Magnum Hunter’s Eagle Ford assets, but also through our own grass-roots efforts to grow our acreage position both updip and downdip, and extend it to the northeast,” says John Brooks, executive vice president of operations at Penn Virginia.

“We’ve had good success extending the play downdip or southeast into Lavaca County, an area that was previously regarded as noncommercial. The risk was that it was perceived to be in the dry-gas window. What we found instead is that we were getting into a very high-pressure volatile oil window.”

Penn Virginia is ”all in” when it comes to the Eagle Ford. The Radnor, Pennsylvania-based independent grew its Eagle Ford position from 6,800 net acres in 2010 to more than 62,000 in three years and is allocating 90% of its $490 million in 2013 capital investment to the Eagle Ford. In 2013, the company expects more than 80% of revenues will come from crude oil, up from 40% in 2011, and is targeting EURs of 400,000 BOE in Gonzales County and 500,000 BOE in neighboring Lavaca County.

A significant part of Penn Virginia’s transition from gas to oil derived from the $400-million acquisition of 19,200 net acres along the Gonzales/Lavaca county lines formerly operated by Magnum Hunter. The deal, along with recent leasing, has more than doubled Penn Virginia’s Eagle Ford drilling inventory to 750 net wells.

“That was a large transaction for a company our size,” Brooks says. “Right now it is just an execution story for us to go out and keep doing what we are doing to prove to the market that it is repeatable for us and that we can deliver the kinds of economics we have been talking about.”

The company is targeting 300 additional infill locations through downspacing, which is improving EURs, and will operate a four-rig program in 2013 and beyond as it transitions to pad drilling.

“As we go to tighter spacing, we are seeing higher recovery factors, because we are able to rubble-ize the rock a lot better,” Brooks says. “It’s early to make those distinctions, but all indications are that those higher IPs and EURs are due to zipper fracs and more effective completions.”

All unconventional plays evolve through a series of phases, beginning with a land grab, delineation efforts to identify reservoir sweet spots, and the optimization of drilling and completion practices to produce the most effective results. During the first three phases, operators outspend cash flow. It is the in the fourth phase, the resource harvest phase, where operators turn cash-flow positive. That is the transformation the new revolution in oil and gas promises. In 2013, the Eagle Ford stands on the threshold of resource harvest, with several operators expecting to turn cash-flow positive by mid-decade.

How the trend unfolds in the Eagle Ford will say a lot about the future of unconventional oil in North America. For generations, devotees of Texas history and its revolutionary origins in Gonzales, San Antonio and Goliad recall the phrase “Come and Take It.” They recall, too, the phrases “Remember the Alamo, Remember Goliad!”

Decades hence, when discussion turns to the unconventional oil revolution in Texas, they shall also remember the Eagle Ford shale.