Posted on 01/18/2011 9:42:23 AM PST by thackney
A historic oil field south of Houston, seemingly on its last leg after more than 80 years in service, is making a comeback.
A North Texas company has launched a sweeping project to tap potentially huge oil reserves still left in the ground at the famed Hastings field, located between Alvin and Pearland.
The project aims to free stranded oil by injecting carbon dioxide into the once-prolific reservoir in a process used since the 1970s in West Texas to coax more crude from aging fields.
It is made possible by a new $1 billion pipeline that carries the gas from south Louisiana to Hastings, and that eventually could help revive a number of dormant fields along the Gulf Coast.
Using conventional extraction methods, oil companies typically recover about a third of the oil in a reservoir. When carbon dioxide is injected into a well, however, it mixes with trapped oil and creates a new fluid that is less viscous and flows out more easily. Recovery rates can rise to 60 percent.
Plano-based Denbury Resources still has months of work to do before the project begins producing oil.
That work includes building new infrastructure and pulling up decades’ worth of oil field detritus.
And it includes winning over residents, not all of them excited about the prospect of yet another new oil development at Hastings.
“There’s a lot of scars on the acreage over the years,” said Marty Toombs, operations engineer for Denbury, during a recent tour of the field.
The Hastings project arrives as rising crude prices are providing fresh incentive for oil companies to pursue more costly or experimental projects that otherwise might not be feasible.
It also highlights the potential of enhanced oil recovery techniques, both to boost U.S. oil supplies and to dispose of large quantities of carbon dioxide, a heat-trapping gas linked to climate change.
The techniques could produce 85 billion additional barrels of oil in U.S. oil fields, with more than half of that profitable to extract at crude prices above $70 a barrel, according to a study early last year by Advanced Resources International.
Output could be even higher if regulators created incentives to capture carbon dioxide from industrial sources like power plants and steer it to oil production, the group said.
In Texas, one of the top oil-producing states, carbon dioxide-enhanced oil recovery projects already account for more than 15 percent of the average annual oil production, though most is from mature fields in West Texas’ Permian Basin, according to the University of Texas’ Bureau of Economic Geology.
Outside the Permian Basin, more than 5.7 billion additional barrels of oil could be produced statewide using the technology, the bureau estimates.
Susan Hovorka, a senior research scientist at the bureau, said it’s impossible to estimate the cost of going after those barrels, given variables like drilling expenses, cost of carbon dioxide and other factors. But with oil now trading around $90 a barrel, she said, investors are interested.
To this point, the biggest obstacle in redeveloping Gulf Coast fields like Hastings has been lack of a readily available source of carbon dioxide.
Denbury’s 320-mile Green Pipeline changes that. It transports carbon dioxide, mined in Mississippi, from Donaldsonville, La., to the Hastings field. Ultimately, Denbury hopes it also will carry carbon dioxide collected from Gulf Coast refiners, chemical plants and other industrial facilities — and be extended to other fields, including the much larger Conroe oil field in Montgomery County.
The Hastings field was discovered in 1934 by Stanolind Oil and Gas Co. and has produced about 600 million barrels of oil from 600 wells over its life. After hitting peak production of 75,000 barrels per day in the mid-1970s, it now yields just 1,000 barrels a day, according to Denbury, which took over the western portion of the field in early 2009.
Toombs, the operations engineer, said Denbury has been able to boost output at similar fields up to eightfold by injecting carbon dioxide.
He declined to share forecasts for Hastings but noted, “Denbury did not purchase this property to operate it as is.”
The firm, which started carbon dioxide injections in four wells at Hastings last month, expects to start producing oil late this year.
Already, some area residents have complained about construction noise, gassy smells and garbage, and Denbury has held community meetings to address concerns.
But Sarah Fusig, 32, who lives near Pearland and within the 4,500-acre footprint of the Hastings field, said the company so far has proven to be a good neighbor.
She recalls an instance in April when crews operating near her house splashed oil on her truck and Denbury paid to have it detailed.
“We have no complaints about Denbury,” she said.
Denbury, which hopes to extend the life of Hastings by another 20 or 30 years, said it is determined to keep it that way.
Can we get some carbon credits and green dollars for this oil production? (only kidding, no subsidies please)
So funny whenever the enviros create a problem, technology usually comes along to solve it.
How long before Obama’s EPA shuts it down?
Obama: This Must Be Stopped.
Has anyone noticed that now, all of a sudden, after two years of misery, he has put out this directive?
First shot of the 2012 re-election campaign!
—CO2 injection in oil fields, being a proven technology, apparently doesn’t leak out like that “reservoir” in Canada referenced here last week, where the injection of millons of cubic feet of carbon dioxide has caused the streams to taste like stale pop-—
Do you have a link? I missed that one.
Thanks
Is this the same?
If injected into a field that previously held oil/gas under pressure, it at least has some proved history of holding.
What the heck is a "carbon dioxide mine"?
Denbury currently uses carbon dioxide (CO2) from our underground natural source at Jackson Dome located near Jackson, Mississippi. Such natural sources are rare, and to our knowledge, we have the only large natural source of CO2 in the Gulf Coast region.
http://denbury.com/index.php?id=16
Mined, like Natural Gas is “mined”.
Getting 35% of the original oil in place usually would make any operator thrilled right down to the ground. Most times the oil industry the recovery is LESS than 35%.
More than 65% of the original oil in reservoirs that have ever been produced is still there. A potential gold mine beneath our feet if we could ever figure out how to get it.
Some oil is what we call immovable, stuck to the sand or rock of the reservoir that it is in or trapped by very large capillary forces. Still, there is oil that may be recovered someday by someone.
I think they mean after a secondary recovery method like water flood.
From the DOE:
http://www.fe.doe.gov/programs/oilgas/eor/
Crude oil development and production in U.S. oil reservoirs can include up to three distinct phases: primary, secondary, and tertiary (or enhanced) recovery. During primary recovery, the natural pressure of the reservoir or gravity drive oil into the wellbore, combined with artificial lift techniques (such as pumps) which bring the oil to the surface. But only about 10 percent of a reservoir’s original oil in place is typically produced during primary recovery. Secondary recovery techniques extend a field’s productive life generally by injecting water or gas to displace oil and drive it to a production wellbore, resulting in the recovery of 20 to 40 percent of the original oil in place.
Yes, what I think I said. 35% recovery is pretty good and it goes down from there. Lots of fields have had pressure maintenance or water flooding for decades. Some though, like areas of the East Texas Field that have never been unitized into very big blocks have had either no or very spotty and ineffective water floods.
Primary recovery really depends on the driving mechanism of the reservoir. modes of primary recovery involve depletion (low recovery), water drive (higher recovery), compaction drive (higher yet recovery in primary mode).
Recovery in cases where the gas cap is destroyed early and the oil becomes immobile and unrecoverable is usually dismal and lots of oil was wasted and for all practical purposes lost forever.
That has been one of the concerns with the proposed Alaskan Gas Pipeline. Some have explained taking the gas pressure down too early will result in lower total dollars for the state.
—that’s the one—
That is also an old oil field. But I don’t know if they are at or below the original field pressure.
And the water injection project begun more than a decade ago has probably not caught up to replace the void left by the oil removed before the water injection began.
Most times, we figure out that unless we begin water injection for voidage replacement with the first barrel of oil pumped we never catch up. Perforations can only take so much water so fast.
Blowing down the PBU gas cap too fast most likely will reduce oil recovery. Because we can recover gas just about any time we usually figure on recovering only solution gas until primary recovery ends and then we produce the remaining gas cap. In a time value consideration this makes the gas more-or-less worthless as a portion of NPV. But boy what a dividend producer someday!! Of course, by that time someone is finally looking at how to pay for abandonment.
I guess it would seem novel to youngsters that working oil wells were spread all around Houston. I remember seeing them pumping away along South Post Oak near the South Loop back in the early 1960’s.
You ever amble into the Ice House on So. Post Oak and HWY 90?
No.
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