No. The Eagle-Ford field is in Texas, with a bit crossing into Mexico. The Texas portion is almost entirely private land leases. Lots of big acreage ranches through this area.
Posted on 12/12/2012 6:53:16 AM PST by thackney
LNG and diesel were used to fuel the pumps that pressurized the Water/Sand/Chemical mixture that was pumped downhole.
CAT also has a partnership with WPRT.
- I wonder if these pumping engines used CAT engines with WPRT fuel systems?
Anyone?
Thanks for that. Looks like Ferus wasn’t first.
- - - - - -
Separately this week, Houston-based Baker Hughes (NYSE:BHI) said that its Baker Hughes Oilfield Operations subsidiary has converted a fleet of its Rhino brand hydraulic fracturing units to bifuel (dual fuel) pumps, and that it recently completed a hydraulic fracturing job in the Eagle Ford Shale for Cheyenne Petroleum.
Pierce Dehring of Baker Hughes outlined a QSK50 conversion program at late September’s BBP Summit in Houston.
Baker Hughes had by then converted four units in Canada using two different conversion systems, and ten units in the U.S. with ComAp kits, which according to Dehring were fully commissioned and job ready. A job was to commence in early October, he said.
Dehring said that a typical South Texas fracking operation could consume 6,000 gallons of diesel per day, with each engine consuming as much as 110 gallons of diesel per hour. The dual fuel conversions “easily” displaced 60% of the diesel with LNG. Baker Hughes cited 65% displacement at the Eagle Ford shale in its release this week.
“Note: LNG was not pumped as the fluid used underground to create the cracks.”
That was what I first thought when I read the headline. I didn’t figure it out until about the third paragraph, then it all made sense.
Thackney, one reason I love your posts: My neice’s husband sells drilling mud and other drilling materials to the operators down in Eagle Ford. Great guy. Your posts allow me to have a halfway intelligent conversation with him. He says there is another play in strata even deeper in Eagle Ford, but the technology to tap into it on a commerical scale isn’t there yet.
I would suspect economics mostly. But technology advance bring unreachable economics closer to grasp. Just as a decade or so ago did for Eagle Ford, Bakken and others.
Colby Williford is vice president of land with Momentum Oil & Gas in Houston, a company focused on geologic formations that run deeper than the Eagle Ford, including the Edwards Limestone, Glen Rose Limestone and Pearsall Formation.
He said the leasing for those formations involved blocks of land already leased for Eagle Ford production.
“Everybody was leased. You couldn’t just look at the courthouse and find the landowner that wasn’t leased. We looked for deep rights that had expired,” Williford said. “There’s multiple ways for deep rights to drop off and other rights to come open.”
http://www.chron.com/business/energy/article/Producers-watch-the-clock-in-Eagle-Ford-4082310.php
That’s interesting. Whoever owns the lease on the current strata probably also got the lease for the deeper strata. As an attorney, I should have considered that angle. So when the top strata plays out, the drilling companies can just go deeper without having to haggle over the rights.
Question: could they use the current well shafts and just drill them deeper, or would they have to drill an entirely new shaft?
And guess who controls these leases? Obama. He’s going to use this “carrot” to reward his cronies. Big money, big oil is on the horizon in the US.
On an older lease almost certainly. Newer leases are more likely to be depth or even field limited. We have done that ourselves.
Question: could they use the current well shafts and just drill them deeper, or would they have to drill an entirely new shaft?
While it is technically feasible to put multi-laterals with perforations at different fields at different levels, it introduces complications not likely worth the savings in trying to produce oil from separate fields in the same well bore.
More likely would be a separate well that allows measurement and the like from each individual field, but put in the same area to share surface equipment and lower maintenance costs.
We do that on the Alaskan North Slope. Add a well 25~40 feet away with separate valving and ability to measure individually the production flow from each field. Then manifold the output together for separation, treatment and shipping of the oil.
Reservoir management can be an art-form to do it very well. Taking the chance of stranding oil or not maximizing production rates can be far more costly than the price of drilling a second well.
Westport Innovations, (WPRT), bought 200 shares a month ago.
No. The Eagle-Ford field is in Texas, with a bit crossing into Mexico. The Texas portion is almost entirely private land leases. Lots of big acreage ranches through this area.
Westport Innovations, (WPRT), bought 200 shares a month ago.
Thanks. Didn’t realize the lands are private.
The main reason the production from places like the Bakken and Eagle Ford are fast climbing is they are mostly private lands.
Makes sense.
I understand that the infrastructure isn’t in place to build the engines, but perhaps the five year window will make it a reality. ?
Lots of federal land in the Bakken area, BLM land, national grasslands and of course T Roosevelt National Park.
Last I heard, and this was within the past year, there was ONE drilling rig on federal ground.
That was just something I picked up in a business meeting, maybe outdated scuttlebutt by now, but the point remains that virtually nothing is taking place on federal land.
Analysts at NASDAQ are bullish and put the price at $38 within a year. Thanks for the tip.
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