Peak Oil is You
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Page added on July 9, 2014
Best Place to Find Oil Is In An Oil Field
Cheap oil has allowed the modern world to develop as it has, but cheap oil is becoming a thing of the past. Oil prices have risen about 10-fold over the past two decades, and the trend is likely to continue as oil becomes scarcer, small and recent fluctuations notwithstanding.
According to some experts, Peak Oil is inevitable because of the world’s finite oil supply. Some worry that the world may have already reached this maximal level of production. Continuing to meet the world’s oil demands until alternative sources of energy replace fossil fuel will require innovation in enhanced oil recovery (EOR) applied to existing reserves.
Basics Truths of Peak Oil
The theory behind Peak Oil is that the oil industry will inevitably reach its peak rate of production. Then, production will hold steady for a time and eventually slow down. Few are likely to recognize Peak Oil before it happens, but many projections point to the period of 2007 to 2025 as the most likely time when it occurs.
Worrisome Signs in Oil Production
U.S. production of oil peaked in the 1970s before gradually decreasing until about 2005. Another sign that Peak Oil may be upon us is that four out of five oil fields worldwide are reducing oil production by an annual average of 8 percent. The Cantarell Oil Field in Mexico, for example, decreased production from 2.2 million barrels of oil per day (BOPD) in 2003 to 1 million BOPD by 2011.
Consequences of Peak Oil
Oil production will hold steady and then drop as the world hits and passes Peak Oil. The consequences could be disastrous for the world. As soon as within the current century, global energy demand will surpass the oil supply. Oil supply is currently meeting demands, but may not for long. The International Energy Agency (IEA) predicts an increase in global oil demand by 50 percent.
The U.S. itself can also be hit hard if domestic oil production declines. The country currently gets 38 percent of its energy from oil. Most is consumed by transportation and no alternative sources of fuel come close to replacing gasoline as transportation’s primary fuel. A drop in U.S. oil production can lead to increased U.S. dependence on foreign energy sources the majority of which are from countries prone to political turmoil like Iraq or Libya or who are outright hostile to U.S. interests like Venezuela.
Complacency Is Not an Option
Alternative sources may one day supply a large portion of the globe’s energy needs but only in the distant future. In February of 2007, the U.S. Government Accounting Office (GAO) presented a report to Congress addressing the potential crisis presented by that peak oil. The report urged development of near term strategies to meet the looming crisis.
Because sustainable energy sources are a long way of from meeting our energy needs, increasing oil production is the most realistic solution for meeting global energy demand. Clearly the easily retrievable oil is diminishing fast and new reserve discoveries are few and far between. However, enhanced oil recovery (EOR) can help the U.S. and world meet current energy needs and can bridge the gap to a time when alternative energy sources can meet global demand.
EOR Can Bridge the Gap
Primary extraction methods are relatively inexpensive because the forces of gravity and natural gas in an oil reserve aid in the recovery of oil. The theory that Peak Oil has been reached mistakenly assumes that primary extraction is the main approach to oil recovery.
Primary extraction only enables the recovery of 5 to 15 percent of the oil in a reserve, and about 65 percent of the oil in existing reserves the world is still untouched. Projections indicate that for each additional 10% of the remaining oil that is recovered, the world’s energy needs can be met for another 20 years. That is where EOR comes in.
Secondary and tertiary extraction methods such as hydraulic fracturing, gas injections, microbial recovery, and thermal recovery are used to increase oil recovery from oil fields. They do not require the discovery of new fields, and can increase recovery to 30 to 65 percent. Plasma pulse technology is a newer method of EOR that has been successfully applied throughout the globe. Initial and ongoing production have increased with plasma pulse. The method doesn’t require chemicals or large volumes of water and instead relies on hydraulic pulse waves to increase permeability of reservoirs and facilitate liquid mobility to the well perforation zone.
Peak Oil may pose challenges to the world’s energy structure but innovation in enhanced oil recovery alleviates some of the issues by meeting energy demand from existing reserves through secondary and tertiary recovery and allows such enhanced recovery at potentially lower financial and environmental cost as with CO2 floods and plasma pulse.
8 Comments on "Best Place to Find Oil Is In An Oil Field"
Plantagenet on Wed, 9th Jul 2014 9:44 pm
The problem with enhanced oil recovery is that collapse from oilfields using EOR is even more rapid when they peak then from traditional oilfields. For instance, Cantarell in Mexico collapsed after peaking so that production dropped by 2/3rds in about a decade.
Beery on Thu, 10th Jul 2014 3:39 am
Enhanced Oil Recovery, AKA scraping the bottom of the barrel.
The article’s author makes out that EOR can somehow extract 100% of the oil in the world. It cannot.
Tomgood on Thu, 10th Jul 2014 5:38 am
Beery, just to play the Devil’s advocate: what do you base your claim that EOR won’t enable the majority of currently unrecoverable oil to be recovered on?
rockman on Thu, 10th Jul 2014 6:47 am
Tom – I’ll cut in line of Beery if it’s OK. First, we in the oil patch may be greedy lying bastards but we aren’t stupid for the most part. EOR methods have been vigorously applied to US fields for more than half a century. The article gives an estimate of average field recovery. Guess what…that includes primary recovery and decades of EOR. I’ve worked Texas oil fields for more than 30 years and I don’t know of one that hasn’t had some form of EOR used if it was applicable. BTW there are many reservoirs where there is no EOR method applicable.
The only useful EOR method that could be a big help is CO2 injection. The problem there is a general lack of CO2 where it’s needed. About a year ago I looked at a field in west Texas that had over 700 million bo of residual oil only 2,400’ below the ground. Recovery for the field was just 11% and was producing only 60 bopd. Offset fields where CO2 was being applied increased recovery to 25%. The problem was those two fields were using all the CO2 available in the area and would continue to do so for decades. So the field with 700+ million bo producing just 60 bopd will continue does so for many years.
But just as higher oil prices have us drilling shales now they would also make previously uneconomic EOR projects viable. That’s the good news. The bad news is that those projects will hardly be noticed when they come on line. So again back to what PO is about: the rate of oil production and not the reserve volume. Such cornucopian articles as this always talk about the hundreds of millions of bbls of oil recoverable by EOR but never mention rates. If one bothered to look at every EOR project in the US they would find many that have produced significant volumes of oil BUT took many decades to do so. A field might have an initial production rate of 10,000 bopd and eventually declines to 1,000 bopd. Some EOR method is applied and might double the recovery of that field. But it won’t do it at 10,000 bopd. More like 1,500 bopd. And while that’s only 500 bopd more than it was producing before remember depletion, like rust, never sleeps. In time that field would have declined to less than 100 bopd.
Bottom line: a significant amount of current US oil production is coming from fields that have had some form of EOR applied for decades. And fields where EOR is suddenly viable thanks to high oil prices won’t bring on a flush of oil like the shales have. It will be a slow drip that lasts for decades…just like the hundreds of thousands of current wells that have been producing for many years thanks to EOR methods.
Mike2 on Thu, 10th Jul 2014 7:15 am
“The only useful EOR method that could be a big help is CO2 injection. The problem there is a general lack of CO2 where it’s needed.”
What is your common CO2 source nowadays? coal/oil/gas-power stations?
And whats about steam flooding? Lots of energy is needed for sure but with nuclear power for example it should be no problem to produce as much ~300°C steam as you ever whished.
I think I heard some rumors about the KSA nuclear program that exactly this is planed in big Saudi fields.
rockman on Thu, 10th Jul 2014 8:53 am
Mike –The most common source for CO2 is natural CO2 reservoirs actually. The bigger ones are in the Rockies. There is a big CO2 field in Mississippi owned by one company. They’ve recently laid a line to the Houston area to inject into a couple of old fields. There are a few industrial sources. There a big one (cogeneration?) up in N Dakota that’s piping it to a field in Canada.
Steam flood and other thermal recover efforts have been going on in the US for more than half a century. Lots of such projects in CA but also some in the Gulf Coast. Yep…takes energy but that’s readily available usually in the form of diesel. Given what a nuke plant costs and the relatively slow recovery of the oil I can’t imagine it would be economical. This would seem to make more sense for the KSA:
BAKERSFIELD, Calif. – February 24, 2011 Noon PST– GlassPoint Solar, a provider of solar steam generators for enhanced oil recovery, today unveiled the world’s first commercial solar EOR project at Berry Petroleum Company’s 21Z lease in McKittrick, California.
Again what you’re asking about is decades old technology that has been applied in every field in the US where it was applicable and economic to do so. The oil patch hasn’t been sitting on hundreds of millions of bbl oil recoverable by some well-established EOR method and not doing it. As I said such articles like this are incredibly misleading for the public that doesn’t realize that EOR HAS BEEN DONE IN HUNDREDS OF FIELDS HERE FOR MANY DECADES. LOL.
In fact there have been oil companies that never drilled an exploration well but instead focused solely on old fields where they would conduct secondary recovery operations. These projects are virtually 100% engineering with little geologic analysis involved.
rockman on Thu, 10th Jul 2014 8:17 pm
Mike – Found some numbers for you. Notice a couple of projects they mention have going on 42 and 51 years. From the O&G Journal 2008:
“Oil & Gas Journal’s exclusive biennial EOR survey shows that the number of EOR projects in the US has increased compared with the last survey taken 2 years ago. Although the current survey lists more projects, total production from all US EOR projects is less than in the last survey.
Production decline in California steam injection projects mostly accounts for the lower production, while new carbon dioxide floods mostly account for the increase in projects.
OGJ’s survey shows EOR contributing 643,000 b/d to US oil production, a 9,700-bo/d decrease from the 2006 survey. The production numbers represent the estimated production at the beginning of the year.
The survey includes 184 active projects, an increase of 32 compared with the 2006 survey.
Oil production decline in the mature thermal heavy-oil projects, mostly in California, is the main explanation for production decreasing. Production from US projects using thermal methods peaked in 1986 at 480,000 bo/d and has declined to the current 292,000 bo/d, or 12,000 bo/d less than shown in the 2006 survey.
Chevron Corp.’s operated Kern River field remains the largest single EOR project in the US, producing about 83,000 b/d, based on California Conservation Department statistics.
Aera Energy LLC, a venture of ExxonMobil Corp. and Shell Inc., produces 95,000 bo/d from 17 projects, but this is a decrease from the 107,000 bo/d listed in the 2006 survey.
Oil production from in situ combustion has increased to 17,000 bo/d or 4,000 bo/d more than in the last survey. Encore Acquisition Co. has three projects while Continental Resources Inc. has 12 in fields in North and South Dakota as well as in Montana.
The combustion project with the most production is Continental Resources’ Ceder Hill North Unit in Bowman County, ND. The company says the unit produces 11,500 bo/d or an increase of 3,400 bo/d from the last survey.
Thermal projects typically have long lives. For instance, the fire flood in Louisiana’s Bellevue field started in 1970 and the field still produces 280 bo/d, while steam injection started in California’s Belridge field, now operated by Aera, in 1961; the field currently produces 33,000 bo/d.
Steam injection projects outside of California also include a TXCO pilot in the Maverick basin of South Texas and MegaWest Energy’s planned pilot in Vernon County, Mo.
In the US, the number of CO2 miscible injection projects for enhancing oil recovery has increased (Table 1). The survey lists 100 ongoing projects compared with the 79 in the 2006 survey. Enhanced oil recovered from these projects also has increased to 240,000 b/d from the 235,000 b/d shown in the previous survey.
Units of Occidental Petroleum Corp. continue to add CO2 projects. Oxy now operates 28 projects compared with 27 listed in the 2006 survey.
Denbury Resources Inc. also has added CO2 floods. It now has 13 active floods compared with 7 listed in the previous survey. All of its CO2 floods are in Mississippi except for one in Louisiana. Fig. 1 shows Denbury’s existing and planned fields.
BTW Danbury owns the only CO2 files East of the Mississippi.
Oxy’s Wasson Denver Unit is the field with the most CO2 EOR production, producing 26,850 bo/d. CO2 injection in the field started in 1983.
Most US hydrocarbon miscible projects are on the North Slope of Alaska with the largest in the Prudhoe Bay and Kuparuk River fields.
The survey does not include any US EOR projects that involve injecting surfactants, polymers, or other chemicals. These projects tend to be smaller and with shorter lives, and operators chose not to respond to the survey.
One recent announcement on a chemical flood is Rex Energy’s plan for starting two alkali-surfactant-polymer (ASP) pilots in an old oil field in the Illinois basin in second-quarter 2008. (OGJ, Feb. 11, 2008, p. 39).
The pilots will be on 1-acre spacing in Lawrence field, near Bridgeport, Ill. Lawrence field, discovered in 1906, still produces about 1,800 bo/d from 1,000 wells and Rex Energy says initial oil in place in the field, the largest in the Illinois basin, was an estimated 1 billion bbl of which about 400 million bbl has been produced
Another chemical flood is Cano Petroleum Inc. alkaline-surfactant-polymer pilot consisting of four wells on 2.5 acres in the Nowata field. ASP injection started toward the end of 2007 and Cano expects incremental oil production in 2008.
CO2 availability
Availability of CO2 limits industry’s ability to expand CO2 EOR flooding in the US. Charles Fox, vice-president of Kinder Morgan Carbon Dioxide Co., told OGJ that the company had completed its DOE canyon gas plant in southwestern Colorado in early 2008, thereby adding 107 MMcfd of CO2 availability to the Permian basin of West Texas and New Mexico. He added that expansion in McElmo dome, also in Colorado, by mid-2008 will add another 200 MMcfd of CO2 production capacity. The addition CO2 form McElmo dome and DOE canyon has been already sold to existing projects and to the North Ward Estes EOR project, which is the anchor field for deliveries from DOE canyon, Fox said.
In 2007, Fox noted that the average amount of CO2 deliveries to the Permian basin was 1.371 bcf/day, broken down as 966 MMcfd from McElmo dome, 290 MMcfd from Bravo dome, 40 MMcfd from Sheep Mountain, and 75 MMcfd from Val Verde gas plants. These deliveries were slightly less than the 1.388 bcf/day delivered in 2006. Fox explains that the lower deliveries were due to an imbalance in demand and supply during summer 2007. He expects CO2 deliveries to the Permian basin during 2008 will set a record.
Enhanced Oil Resources Inc. recently announce a memorandum of understanding (MOU) for developing a pipeline with SunCoast Energy Corp. to carry CO2 350 miles from its St. Johns, Ariz., helium and CO2 field to the Permian basin. The company’s initial plans are to transport 350 MMcfd of CO2 into the Permian basin. The pipeline design capacity will be 500 MMcfd.
EOR Inc. has reserved the right to the first 175 MMcfd of capacity for its own oil field in the basin and for some other targeted fields.
If both company’s meet their obligations, EOR Inc. expects the pipeline to be built by late 2010.
Denbury has plans to increase its CO2 pipeline, with one possible line transporting CO2 into East Texas. The company also has signed CO2 purchase contracts with three planned chemical plants. In a January presentation, Denbury said, contingent on the plants being built, it expects to obtain:
•190-225 MMcfd from the Faustina petroleum coke gasification plant, Donaldsonville, La., starting in 2010.
•190-225 MMcfd from the USTransCarbon gasification plant, Beaumont, Tex., starting in 2011.
•350-400 MMcfd from the Rentech gasification plant, Natchez, Miss., starting in 2011-12.
In Wyoming, Anadarko Corp. has plans to extend to the Linch-Sussex area its 125-mile pipeline that currently transports CO2 to the Salt Creek and Monell fields. The La Barge gas plant is the source for this CO2.”
Tomgood on Fri, 11th Jul 2014 5:09 am
Rockman: thanks for that explanation – in other words, it’s like I read somewhere that it’s not the size of the barrel that’s important, but the size of the tap that counts. Your post are always appreciated.