[khebab]

The last blog on the oil drum is about Enhanced Oil Recovery (EOR):
There is some good news

There is an article about an experiment in Canada using CO2:
Globe and Mail

Carbon-dioxide injection will allow EnCana to extract another 140 million barrels of oil from its 51-year-old Weyburn field, an enormous volume at a time when the average new well drilled in Western Canada yields a mere 50,000 barrels.

I was wondering why Tertiary recovery techniques are not much addressed on this forum?

Is it hopeless or can we expect significant production increase from EOR?

[Tyler_JC]

Here's the problem. We ARE using those techniques. That's what's allowing us to maintain production in Ghawar and in donens of other very old and very large oil fields. EOR is great in the short term, but it leads to damaged fields and lower total production at the end of the day. Also, EOR uses more energy/costs more than normal production techniques.

I think the reason EOR isn't really discussed much is because we are currently using gas-injection and water-injection in many parts of the world right now. It's not so much a question of "will we get more oil out using EOR?" but a question of, "when will these fancy recovery techniques stop working?"

Oman is a great example of this. They used all sorts of maximum recovery technology. I believe they also used gas-injection. They were a major oil producer until they peaked a few years ago. Now Oman is declining at 8%-10% a year with no signs of improving .

[Aaron]

What he said.

MRE technology has been discussed many times here.

It may well turn out to be the straw that breaks the camel's back, in terms of post peak depletion rates as Tyler mentioned.

[rockdoc123]

An interesting sideline to the Oman story is that the Omanis are apparently fairly peed off with Shell/PDO for the poor job they believe they have done with respect to secondary recovery. They recently took one of their fields away from them and gave it to another company (can't remember if it was Repsol or who). Likely the Omanis are in denial.

[0mar]

The last blog on the oil drum is about Enhanced Oil Recovery (EOR):
There is some good news

There is an article about an experiment in Canada using CO2:
Globe and Mail

Carbon-dioxide injection will allow EnCana to extract another 140 million barrels of oil from its 51-year-old Weyburn field, an enormous volume at a time when the average new well drilled in Western Canada yields a mere 50,000 barrels.

I was wondering why Tertiary recovery techniques are not much addressed on this forum?

Is it hopeless or can we expect significant production increase from EOR?

ASPO's model already accounts for these sorts of things, and they are industry standard operating procedures for the last 30 years.

[Tyler_JC]

Aaron,

What he said.

That's because I was basically quoting you about Oman and maximum recovery techniques.

[RonMN]

Question: How much energy does it take to make "liquid Co2"??? (EROEI)

[khebab]

What he said.

MRE technology has been discussed many times here.

It may well turn out to be the straw that breaks the camel's back, in terms of post peak depletion rates as Tyler mentioned.

Well, I guess the article title from the oil drum was misleading, it's not "good news" but rather "old news".

[khebab]

Question: How much energy does it take to make "liquid Co2"??? (EROEI)

hmm.. well, a lot!

“Pressuring it to the liquid stage, putting it into the pipeline, and transferring it to the storage site — that’s very energy intensive,” says Curt White, a focus area leader of carbon sequestration science at the U.S. Department of Energy’s National Energy Technology Laboratory. It is also expensive. He estimates carbon capture now costs in the low thirties of dollars per 1,000 tons. “That’s way too expensive. We’ve got to get the cost down. We’ve got to make it definitely more economic.”

src:Demonstrating Carbon Sequestration

[Starvid]

Still the EROI of that process doesn't really matter. We are dealing with peak oil, not peak energy.

We have a liquid fuel crisis, not an energy crisis.

[Tyler_JC]

Still the EROI of that process doesn't really matter. We are dealing with peak oil, not peak energy.

We have a liquid fuel crisis, not an energy crisis.

But if much of that expended energy is in the form of liquid fuel, it is relevent. Besides, a low EROEI means a low Money Return on Money Investment. That's why some fuels cost more than others. If it costs 10 dollars to get a unit of energy from oil and more than 40 dollars to get a unit of energy from nuclear, nuclear will cost more. (I'm not saying that nuclear is more expensive, I'm just quantifying EROEI).

Again, if we must use trucks to transport this liquid CO2 or feed the people driving the trucks, it will cut into our energy bottom line.

[FatherOfTwo]

Here's the problem. We ARE using those techniques. That's what's allowing us to maintain production in Ghawar and in donens of other very old and very large oil fields. EOR is great in the short term, but it leads to damaged fields and lower total production at the end of the day. Also, EOR uses more energy/costs more than normal production techniques.

Oman is a great example of this. They used all sorts of maximum recovery technology. I believe they also used gas-injection. They were a major oil producer until they peaked a few years ago. Now Oman is declining at 8%-10% a year with no signs of improving .

I don’t think we are comparing apples to apples. Water injection can damage a well making it more likely to produce more oil now, but less oil in total. What type of gas injection are you referring to?

The CO2 technology is different. They are applying the technology to the wells that have been declared “dry” and getting significant returns. That is fundamentally different.

The catch is having a reliable, substantial supply of CO2, which is why Norway has ruled it out, and why it (along with the oil sands production of CO2) make it very feasible in Canada.

[khebab]

There is a section about gas injection in Energy Technologies at the Cutting Edge (an IEA publication):

It is estimated that by using Enhanced Oil Recovery
(EOR) techniques, 300 billion barrels of previously
inaccessible crude oil (nearly two out of every three
barrels of oil) from known reservoirs could be tapped.
This is equivalent to the amount of proven reserves in
Saudi Arabia - enormous potential, to say the least.

They seem to be excessively optimist as usual.

[khebab]

An interesting Chinese project about CO2 based recovery:

The project is examining the injection of boiler flue gas for enhanced oil recovery coupled with CO2 sequestration in a Chinese oil field

A project is underway at the Liaohe Oil Field (LOF), pumping boiler flue gas into an oil reservoir in order to boost oil output. Production from the LOF is declining and had previously adopted steam pumping into the reservoir for increased oil recovery. However, efforts have now been directed to the application of boiler flue gas containing 12-13% CO2 for this purpose. This fulfils the dual role of increasing oil production and sequestering CO2.

The initial objective of the project was to inject steam and flue gas simultaneously (via a concentric pipe) without pre-mixing them. The flue gas comprised 12-13% CO2, the remainder being nitrogen etc. Following injection, the well was closed for a few days to allow the gases to fully diffuse and penetrate the reservoir. Preliminary results indicated that the EOR effect created by steam-flue gas pumping was considerable. With steam alone, oil increases of 20-30% were achieved. However, using the combination, levels increased by 50-60%. The technique can be applied equally to a single well or multiple units covering a large area.

The actual process of flue gas injection comprises a number of stages that include: gas collection, gas cooling and dust removal, gas purification followed by re-cooling in readiness for drying, compressing and measuring, further treatment through mixing with additives, and pumping underground.

Huafu is continuing to test the effectiveness of using pre-mixed flue gas with water for EOR purposes. An R&D project is also planned, injecting CO2 separated from flue gas via membrane technology.

To date, conclusions suggest that the technique is very effective in enhancing oil recovery from wells characterised by declining production. In addition, it provides an attractive and cost-effective way of sequestering CO2. Further tests are planned and during the second phase of the project, it is intended that flue gas will be captured from an oil-fired boiler. Efforts will be made to enrich the CO2 level of the gas by its recirculation in the combustion system; H2S removal may also be carried out prior to injection into the well

[Tanada]

If all you want to do is pump CO2 and N2 into the injection well it would be simple to set up a coke burning operation to produce the needed gasses. Even better if you use Blast Furnace gas after it has been mostly combusted to reduce the CO to CO2. This gives you carbon sequastration and the gas is already nearly sulfur free, and dust can be electro statically filtered out before mixing with steam and injection.

Thoughts?

[Graeme]

The Global Prospects For Enhanced Oil Recovery

Increasingly, a majority of oil companies are trying to maximize the recovery factor (RF) of existing fields and turn to unconventional extraction techniques. On average, the worldwide production potential of oil is between 20 percent and 40 percent. Compared to the typical 80 percent to 90 percent RF from gas fields, this figure seems rather puzzling. With high oil prices in the offing, enhanced oil recovery (EOR) is being seen as an answer to the challenge of improved recovery.

In the UK, the Wood Review has been adamant about the importance of such schemes to maximise the future of North Sea oil and extend the life of a declining petroleum province.

Petroleum extraction occurs typically in three stages: primary, secondary and tertiary recovery. Oil and gas are extracted by creating a pressure gradient inside the drilled reservoirs. By maintaining a pressure differential between the reservoir and the surface, it forces the stream of hydrocarbons through the well.



According to a recent study from Visiongain, oil extracted by chemical EOR processes will produce 377,685 bbl/d by the end of 2014, amounting to a $2.25 billion expenditure. In general, gas injection is more economical and is used when gas is a by-product of the oil production. The technique has gained in popularity due to the possibilities of connection with carbon capture and storage (CCS) schemes to create a CO2 value chain. It represented 35 percent of EOR market share in 2012, against only 5 percent for chemical injection, and a lion’s share of 60 percent for thermal processes.

oilprice

[ROCKMAN]

"I was wondering why Tertiary recovery techniques are not much addressed on this forum?" The very short answer is that this forum deals with the ramifications of peak oil rates and not peak oil reserves. If you notice such discussion usually focus of the increase in URR. And little discussion of the additional production RATES of such efforts. And more to the point with regards to the US: every field in the US where any EOR method had an application and was economical to do at the time HAS BEEN DONE. And has been going on in some trends FOR MORE THAN HALF A CENTURY.

There is no inventory of oil fields in the US like gold laying on the ground waiting for anyone to come along and pick up. A significant portion of US oil production current come from fields that have been undergoing EOR for decades. Articles hyping US EOR recovery potential give a very false AND DANGEROUS impression to the public IIMHO. We in the oil patch depend upon producing hydrocarbons. A bit of common sense should tell anyone that if there were techniques available to recover billions of bbls of oil economically via EOR we would have done it. Here's some facts these reports never mention:

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. Denbury’s existing and planned fields.

{BTW Danbury owns the only CO2 field 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). 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.”

And here's a short and sad story I was personally involved with: 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. I evaluated every other EOR method and they were either not application or the economics didn't fly.

But here is some optimism for Middle East fields that might benefit from thermal EOR: 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.

[Scrub Puller]

Yair . . .

So the field with 700+ million bo producing just 60 bopd will continue does so for many years.

Would'nt that be a nice mum and dad operation if there weren't to many costs.

Cheers.

[ROCKMAN]

SC - Very frustrating for me. If I could have come up with an applicable and economic EOR method that required a $50 million investment my owner would have written the check for the full amount that day. Such projects are a young engineer's fantasy: a 28 yo production engineer could work on that one project his entire career all the way to retirement. It would be more like an annuity than a job.

[Graeme]

Rock, The key point in the article is:

Tertiary recovery, or EOR, is a set of techniques that enable to increase the global recovery factor beyond the 35 to 40 percent target. Alain Labastie, a former president of the Society of Petroleum Engineers, says that a 10 percent increase in the RF could bring about 1 trillion barrels of oil. Two years ago, a report by Shell estimated that a mere 1 percent increase in the global efficiency of hydrocarbon recovery would raise conventional oil reserves by up to 88 billion barrels, the equivalent of three years of annual production at today’s levels.

It didn't say there are new EOR techniques. Rather than looking for new fields, industry should focus on existing ones using traditional EOR methods. I tried to help you out because I realise we need ff as we gradually transition to 100% renewables.