Things aren’t always what they seem. What starts as a natural gas play can become an oil/gas liquids play. Sometimes the best thing to do is circle back to your roots. But it’s important to always know where you are, especially when you’re in the Eagle Ford Shale in South Texas.
Starting in 2006 Pioneer Natural Resources Co. returned from a foray into the Gulf of Mexico to focus again on the Spraberry Trend of west-central Texas, as well as the Eagle Ford and the Barnett Combo in North Texas. It apparently was a good move.
“I never would have thought we would have found what we have in any of these three plays to date,” Pioneer CEO Scott Sheffield told attendees at Hart Energy Publishing’s Developing Unconventional Gas: Eagle Ford conference in San Antonio, TX, last week.
Perhaps because he’s been in the Spraberry Oil Field for 31 years, Sheffield couldn’t resist talking about it at the Eagle Ford conference. It’s “probably the biggest boom play that I’ve seen in the past couple years. It’s at an all-time high, 170 rigs running in this play; it’s probably going over 200 rigs.”
That enthusiasm is indicative of the industry’s lust for oil and liquids plays in an era of $4 gas that offers no end in sight.
The Eagle Ford began as a natural gas play — and it still is, in part — with discoveries by Petrohawk Energy Corp. “Now I classify it as the largest oil discovery since Prudhoe Bay…” Sheffield said. Recent reserve projections of 150 Tcf in the Eagle Ford exclude the oil portion of the play. “So it’s going to grow significantly,” he said. “And roughly we’re estimating now that about half of the play will be related to condensate and oil.
“That’s why the rig count has jumped. It’s up to 120 rigs, and based on the number of JVs [joint ventures] that I know will probably get done, this rig count will be up over 200 rigs in the next 12 to 18 months in this play.”
Today’s market economics clearly favor the development of the Eagle Ford’s oil and wet gas resource (see NGI, Oct. 4).
Dallas-based Pioneer got active in the South Texas region where the Eagle Ford lies back in the mid-1980s when it was working the Edwards Trend, a formation below the Eagle Ford. In 2006 when the company refocused on South Texas it bought most of its acreage there for around $150-200/acre, Sheffield said. Pioneer drilled through the Eagle Ford and Edwards, took cores and began testing on the Eagle Ford in 2006. “We have shot over 2,000 square miles of 3-D seismic, so we probably have the best seismic database because it was already pre-shot before all the Eagle Ford announcements,” Sheffield said.
And then Pioneer struck its Eagle Ford JV with India’s Reliance Industries Ltd., a $1.15 billion deal (see NGI, June 28). From five Eagle Ford rigs currently, Sheffield projects the tally to be seven by year-end and 14 rigs within the next 12-18 months.
“We’re in the best part, the deepest part, the most pressurized part of the play in what we call the condensate area, where 80% of our acreage is in the rich and lean condensate area of the play,” Sheffield said. Pioneer has virtually nothing in the play’s oil window, so its interests lie in condensate, natural gas liquids and dry gas.
The Eagle Ford spans 330 miles across Texas and also lies in Mexico, where Sheffield said he’s heard that the country’s Petroleos Mexicanos has begun drilling Eagle Ford wells. The resource can change quickly as one moves across the play, from dry gas to liquids-rich gas in just six miles, Sheffield said. “You need to know exactly where you are. It’s important to have 3-D seismic in this play to know where to put your horizontal wells.”
The frenzy in the Eagle Ford will be drawing pressure pumping resources from dry gas plays such as the Haynesville Shale in North Louisiana and elsewhere, Sheffield said, since the oilfield services industry does not have enough assets on the ground to cover the soon-to-come hydraulic fracturing needs of the Eagle Ford. For its part, Pioneer will own a portion of the pressure pumping fleets it utilizes, a business model it began in the Raton Basin in Colorado about six years ago.
“We’re glad we did [that] because these service companies have not been able to provide the equipment to date,” Sheffield said. “It will get worse.”
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