Tech Talk - Past, Present and Future Venezuelan oil production
Posted by Heading Out on January 16, 2011 - 8:42am
Last week I wrote a little about the planned production of heavy oil from the Orinoco Basin in Venezuela and used that as the basis for a discussion on API gravity and refinery gains. What I would like to do today is to revisit this area of Venezuela and discuss a little more of the region and the potential for increased production, and how it might be achieved. But let me start with overall production from Venezuela, for which (as my comment on Chinese imports last week exemplified) data is not always consistent.
Taking the curve developed at Energy Export Data Browser for the country, the initial impression is a classic example of a depleting system, with rising internal consumption having a negative impact on overall exports, which have already fallen below 2 mbd. The EIA note (and this has been a problem for a while) that it is difficult to assess the make-up of the production stream, but estimate that in 2008 about 250,000 bd came from condensate, NGLs and refinery gains. The United States has seen a steady decline in the amount of oil that it imports from Venezeula, with the daily rate falling below 1 mbd towards the end of last year. Within the past two weeks it has fallen as low as 650,000 bd.
Overall Venezuela was reported as producing 2.25 mbd in November with production falling over the course of the last year. This is somewhat less than the 3 million barrels that the Venezuelan Oil Minister claims that they are producing. Hopes for the future therefore rest on increased production from oil sands of the Orinoco that I briefly described last time. I should also clear up what may be a little confusion in nomenclature. This is a map of the Belt from a study done by the Baker Institute at Rice in 2002. (H/t KLR)
At that time production came from four strategic operations built around individual upgraders: Petrozuategui, Petromonagas, Petrocedeno, and Petropiar. As some of the references here note, the upgraders are beginning to suffer from a poor record of maintenance and are thus more difficult to maintain at the original levels of production.
More recently there has been a renaming (as in the table) and the bids relate to zones now defined by PdVSA as:
To a degree Venezuela in the same situation as Canada, as conventional production of oil diminishes, so the rise in oil prices is making it more practical to produce the heavier oils of the Orinoco Basin, although almost all the oil from Venezuela is both heavy and sour. However this also may lead to volume calculation concerns since there is a reported 10% loss in volume as the heavy crude passes through the upgraders to be pipelined as a syncrude. Thus from the four major current producers there is a variation between 640,000 bd of raw crude (API gravity between 8 and 9.3 degrees) input; and the 579,000 pf syncrude (API gravity 16 to 32 degrees) that is produced. The heavier crude is also discounted in price, so that, with the OPEC basket at $90.38 at the end of last year, the Venezuelan basket was reported to be selling at $ 84.83. Heavy Oil Guy commented on this loss last week.
Any practical process will have to reject something like 20 wt% of the original crude as useless high-sulfur, high-metals coke or asphaltenes that must be stored forever (or dumped into a deep ocean trench ;-]). Also 10% by weight would come off as fuel gas, including ethylene, that would be burned as process fuel, not recovered as a liquid.
Because of the high specific gravity and viscosity of the oil, particularly when cold, conventional methods of production cannot rely on reservoir pressure to produce the oil. In some cases it is possible to use progressive cavity pumps (Moyno pumps) that are lowered down the wells, to pump the oil out of the reservoir.
The reservoir properties for the Hamaca wells are excellent, with porosity values of up to 36% and permeability values of up to 30 darcies. Hamaca crude is considered 'foamy' and is generally saturated with gas at reservoir conditions. Over the 35-year life of the field, more than 1,000 horizontal laterals are planned to deliver the required 190,000bpd to the upgrader facility.
Oil is produced under 'cold production' methods (no need for heated steam to mobilise the deposits) using progressing cavity pumps to bring oil to the surface. Cold production is possible because of the extended length of the horizontal wells (5,000ft), excellent reservoir properties, and the foamy-oil nature of Hamaca crude.
Once at the surface the crude is mixed with a chemical/diluent that allows it to be pumped to the upgrader. It was the use of the pumps to extract the oil with sand that led to the acronym CHOPS (Cold Heavy Oil Production with Sand), although in an earlier article I discussed the use of the technique in Canada, where higher reservoir pressures and lower viscosity allowed the oil to be produced without the pump, by allowing the well to flow freely.
In Venezuela, though it is thought to be used in many of the heavy oil deposits, it is estimated to be only able to produce 5 – 10% of the oil. Problems are then anticipated to arise in changing the well designs to use alternate means to go after the remaining 90%, and it is anticipated that by 2012 CHOPS will no longer, in consequence, be used in Canada.
With 80% to 90% of the resource still in the ground after cold production, the reservoir is in a disturbed state, perhaps with wormholes or channels that have found a way to water. It may, however, be a severely depleted reservoir with low pressure and a network of channels.
If CHOPS has not been used extensively in Venezuela there are a variety of ways that the heavy oil can be encouraged to flow to the production wells. More modern trends are to rely on such thermal techniques as Steam Assisted Gravity Drainage, (SAGD). These are necessary since the deposits are too deep to be mined using the surface mining techniques that are used in Canada. SAGD is where steam is injected into the formation from one horizontally drilled well, and the heated (and thus less viscous) oil then flows through the deposit to a second well where it is recovered.
An alternate has been proposed, in which single horizontal wells can act both as an injection source for the steam, and then after the oil has been conditioned, they will serve to produce the lower viscosity, hotter fluid.
Kerosene can also be injected into the formation ahead of the steam, which then forces it through the oil. In this way it is claimed that production can be greatly enhanced. However, to be viable more than 70% of the solvent must be recovered for re-use. Canada is also investigating the JIVE process. (Joint Implementation Vapour Extraction)
However all this development will cost a considerable amount of investment, and as Robert Rapier noted last September, Hugo Chavez is not keen to make those investments himself, and the result has been seen in the declining levels of production.
However he is still trying to persuade others to make the investments that he will not, and the evidence, given the perceived coming shortage of oil, and the needs of countries to ensure a steady, stable supply, means that he is currently still able to negotiate deals to get those funds. The different alliances that have evolved for this development can be seen from this map from Petroleum World.
In conclusion there is one more factor that relates to the whole issue of overall Venezuelan production. Last week in this space I mentioned that there was a swap deal for oil involving Venezuela, Belarus and Azerbaijan. This is proving to be a little more complex than the original simple swap I mentioned, since it involved lighter crudes from Venezuela, particularly the Santa Barbara crude which has an API gravity of 39 degrees.
“We have to work with different blends, and in terms of its functional properties, the Santa Barbara blend is among the best. This blend can produce 20 percent more gasoline, kerosene, or diesel fuel than Russian blends, and these products are in high demand in Europe.”
Originally that was being shipped to Belarus in tankers from Venezuela, and my impression initially was that Venezuela was swapping production with Azerbaijan (Venezuelan crude would go to the USA and Azer crude would go to Belarus) as a way of reducing the shipping. However this week, it transpires that the problem apparently is that Venezuela cannot supply sufficient of the sweet crude to meet world demand, and in particular the 30 mb it sold Belarus. PdVSA is thus having to buy Azer crude to make up the difference between what it can send and what it contracted for.
Plans, stated recently by the Belarusian authorities, to use the swap scheme in oil supplies "do not deal with the substitution of Venezuelan oil with Azerbaijan," the diplomat said. "Oil company PDVSA will purchase an additional amount of oil in Azerbaijan to ensure the execution of the contract to supply up to ten million of oil a year to Belarus," ambassador said. This oil will go to Belarus through "Odessa-Brody" pipeline. The Belarusian side will pay Azerbaijan not for the oil itself, but only for its delivery. "As you can see, this cooperation is beneficial for both parties and, in particular, for Belarus," Americo Diaz Nunez said.
Belarus has now found it makes more money (about $30 a ton) doing it this way, since the pipeline is cheaper than the rail transport they would have to pay for in buying from Russia, which also charges a 100% duty. But the limited supplies of the sweet Santa Barbara crude have also been bought by the Japanese. However Venezuela may have a further problem, since in October they signed a deal with Belarus that will increase the amount shipped to 220 mb over the next three years. They are apparently getting $88 a barrel for it. (Though the price for Urals crude to Belarus was only $57 a barrel – that may have been before shipping and duty were added.)
So Venezuela has a global market, the question now becomes as to whether it can supply it.
Contact
- Content: editors at theoildrum dot com
- Tech support: support at theoildrum dot com
License
This work is licensed under a Creative Commons Attribution-Share Alike 3.0 United States License.
OT: Happy birthday, "peak oil": Colin Campbell and 100 months of Peak Oil
Just thought I'd throw that in; considered briefly just writing someone on the staff but hey, why not share this with the lot of you as it happens, and also before I forget. That first newsletter was dispatched Jan 2001; how about a celebratory post about it on TOD? I've been parsing Colin's work, solid stuff and I dare say he also had more than a small bit of influence in the massive disregard for economists we see so often in the peak oil blogs and forums, too. Usually Colin would append "flat earth" as well. Got that right; thanks for nothing, Tom Friedman! You too, Julian Simon.
To fitfully get back on topic, I'm sure Simon would just say that if we think hard enough, we could just melt the Orinoco for pennies on the dollar. Somehow.
KLR,
I'm also a fan of Campbell's newsletters but your comment need not be off-topic. ASPO Newsletter #67 contains Campbell's reliably awesome assessment of the geology, history and politics of the oil situation in Venezuela.
Here is just one interesting paragraph from his detailed 2006 assessment of Venezuela:
For anyone wanting a broader geologic and historical perspective, Campbell's country assessments are invaluable.
Jon
is campbell sticking with his estimate of 60 gb ultimate recovery from ghawar ?
In the April 1997 issue of the Hubbert Center Newsletter (97-2), Colin Campbell used the expression peak production. He also mentioned the situation in Venezuela. L. F. Buz Ivanhoe discussed Venezuela in 1999, (99-3). Campbell contributed more material for the April 2001 (01-2) issue including an item titled 'Peak Oil'. See also 99-4.
http://hubbert.mines.edu/
Excellent posting--very informative--a breath of fresh air from those who only post EIA, IEA, BP or Saudi fairy tale stories !!
When I first started reading about Orinoco, my first impression was that the situation there has the potential for an environmental worst case scenario. This post has reinforced my concerns. Chavez's unwillingness or inability to invest in extraction and maintainence tells me that environmental concerns won't be addressed and the oversight we witness in Canada will be set aside in Venezuela to maximise profits. Some here have argued that oil sands mining in Canada ultimately results in an improved landscape there. Whether or not one agrees with this POV, this clearly won't be the case in the Orinoco belt.
Ghung. Surely you jest
Ha Ha. Good Laugh.
Or maybe Hugo plans on improving the environment of the massive & beautiful Orinoco River just like Alberta is doing with the Peace River & the Athabasca River.
See "Canada Tar Sands Industry Ignoring Toxic River Pollution".
http://atlantic.sierraclub.ca/en/node/2879
and "Investigative Report on Pollution in the Peace River"
http://terrainforma.ca/2010/07/05/special-investigative-report-on-pollut...
Some here have argued that oil sands mining in Canada ultimately results in an improved landscape there
The oil sands companies intend to turn the former mix of muskeg (peat bog) and somewhat spindly trees overlying the oil sands into grazing land. The Alberta government considers this an improvement. It likes the idea of increasing the agricultural area of the province.
Keep in mind that this is not a protected area, it is commercial forest. They intend to clearcut it all regardless of whether the oil sands are developed or not. The difference is whether they replant it to trees or to crops.
...ecologists at the University of Alberta found levels of arsenic, copper, cadmium, lead, mercury, nickel, silver and zinc far in excess of national guidelines downstream from industrial oil sands sites in the Canadian province.
Studies have found arsenic and other heavy metals in the river upstream of the oil sands as well. The Athabasca River is naturally contaminated with arsenic and mercury, as are a number of other Alberta rivers. The question is whether the oil sands mines have significantly increasing the levels in the river.
The problem is that there were no baseline studies to determine what the level was before the oil sands operations started. The oil sands have been flowing oil into the river for time immemorial, so you have to expect some oil contamination even in the absence of industrial development.
As for the Peace River, there are no oil sands mines in the Peace River oil sands, although there are a lot of conventional oil and gas facilities and some in-situ projects in the area.
Keep in mind that this is not a protected area, it is commercial forest. They intend to clearcut it all regardless of whether the oil sands are developed or not. The difference is whether they replant it to trees or to crops.
Back in the day when I was falling timber in the northern US Rockies I could see that a rather small allowance, maybe 1-5%, of the to be harvested area could create substantial cut/forested boundary areas if designed properly. These boundary areas are of extremely high value to a huge crossection of any region's wildlife.
I think the extra planning effort-not that much extra-and change in overall mindset required have been more of hindrance to implementing that sort of cutting design than the relatively small log loss that would be caused by the removal of the timber from the harvest. Slightly larger sales with better timber left standing designs would only require a small amount of additional transport to yield the same harvest as the clear, rectangular swath cutting designs now predominantly used.
I haven't seen much evidence of trying to increase the cut/forested boundary areas in any aerial shots I've seen and find that a crying shame.
In Alberta they typically cut forest in a patchwork fashion, which looks rather odd from the air, but supposedly results in better regrowth since the cut areas are reseeded from the non-harvested areas. Also they leave some trees standing in the harvested area since this promotes reseeding and regrowth.
In the oil sands areas, almost all the forests burned down in massive forest fires during the 1960s, so they look rather uniform. The trees have just about reached harvestable size, so they will likely will be cutting them all in the next few decades.
You have too keep in mind that the total oil sands area is only slightly bigger than England, which from the Alberta perspective is not very big. Alberta is considerably bigger than France and only about 2% smaller than Texas. It has wilderness parks which are bigger than Switzerland. Also, its forests are not all that permanent. During the last interglacial period, they all turned into prairie. It could happen again if what the global warming people predict is correct.
Patchwork with standing sections in the cuts sounds good. The relative sizes of what is left for later and what is cleared can be adjusted for wildlife considerations as well as reforestation potential. However that may be a more obvious concern in a big game mecca like northwest Montana than it would be in large fairly homogenous boreal region.
I've traveled a fair chunk of Alberta's main roads (including rail) south of Peace River over the years but its been about a couple decades since my last pass. No doubt its a big province, as near half of it is north of the large portion I've traversed.
The ice free interior Alaska wasn't forest during the height of the most recent ice age--so I've a good grasp of the impermanence of huge northern forests.
Still England is not a tiny island (or were you referring to the UK of which England composes a bit over a half). That will be a noticeable disturbance in Alberta if it is all mined, but then what sort of time frame is the entire process expected to have. Twenty years of plant recolonization and progressions can make a landscape almost unrecognizable to us.
If its going to take a century or more to mine the sands that are slated to be mined the whole tar sand region's landscape should be far more varied by the end of the mining than the fairly homogenous boreal forest that exists now. Of course whether that will be better or worse is a value judgment that shall continue to marshal forces on either side.
As an aside: I usually learn or relearn something by accident as I click around while composing these posts--this time it was that Russia is bigger than the Arctic Ocean. That is a big country.
Most of the Orinoco Oil belt sectors being produced or slated for development are not on the river - they are dozens of km away from the river itself. The area is not jungle, it's used for farming and planted timber. I think there's a certain agenda behind the comments regarding pollution in the oil belt, as well as a degree of ignorance about what goes on.
I don't particularly like Chavez' politics, but the oil developments in the Oil belt have been carried out in a fairly clean fashion, they are not obstrusive, the plants are clean, and thus far it looks a lot better than the Slaughter Estates Unit or one of the old fields around Lake Charles, Lousiana.
If you want to point the finger at pollution in Venezuela, better go to Lake Maracaibo and nose around.
Its almost cute to see these guys struggle out of the pristine wilderness of the tar pits of California or the coastlines of Texas and Louisana, leaving goopy boot-tracks all the way up to the Alberta border to lob some mortar shells across at the oil sands. ;)
Redux:
"Ghung. Surely you jest"
Jests not, he does.....
The Rice Institute paper I provided said the first rigorous estimates of the size of the Heavy Oil Belt were done in the 1980s, but here's a 1974 news article about the imminent nationalization of Venezuela's oil that includes the kind of ballpark figures that were kicking around then:
This is the earliest excerpt I could find in the Google News Archives, available free of charge - most items are Pay Per View. And without doubt the Orinoco was debated in AAPG, SPE, and the like. How about an advanced search at Google Scholar? Dates are set 1920-1975. With GS if you get a free hit generally it is linked off to the right, with "[PDF] from suchandsuchdomain.com" or the like. And here we have The Challenge of Venezuelan Oil, from 1975:
The Rice paper (pun...) says the detailed estimates almost doubled this OOIP to 1.3 trillion, with 20.5% recoverable = 267 bbo. Interesting that the paper also mentions forecasts of a decline to < 2 mb/d by 1984 - which proved accurate, although perhaps some of that was spare capacity; subsequently they cranked things back up. Was that via outside assistance? The NYT reported in 1996 on the welcoming back of foreign companies; also a goal of 5 mb/d peak by 2005, and a quote from Chris Skrebowski, huh. But they'd been gaining steadily over the years anyway, notably about 300 kb/d for 1991.
2 questions:
(1) what are Venezuela's conventional 2P oil reserves?
(2) annual decline rates of conventional production?
(3) where does the hydrogen come from to produce the syncrude? Do they have sufficient quantities of natural gas?
Answer for Matt:
1) Hard to tell what 2P reserves are because commercial terms seem to be variable. If you include the heavy oil belt and assume the government will eventually put in place reasonable economic terms to develop it, they are easily in excess of 200 billion barrels.
2) Official production statistics for Venezuela are impossible to get. Therefore it's hard to tell what are the conventional oil decline rates. These rates also depend heavily on the operating practices, which can vary. I think it's safe to say the decline rate is 5 % per year.
3) The hydrogen comes from natural gas. The country has huge natural gas reserves, but they are not developed. Some of these reserves are gas caps over giant oil rims or in giant gas condensate reservoirs being cycled by injection, they will be blown down eventually. The blow down date varies and it's confidential. The government does not offer terms allowing non-associated gas field development thus far, therefore undeveloped gas reserves remain undeveloped for the most part. Eventually they will have to do something about it. The gas oil ratio in the heavy oil belt fairly high, therefore primary oil operations are self-sufficient. The need for natural gas increases considerably if a light syncrude is the target for the upgrader, or if thermal operations are to be used.
Eni says Perla well confirms world class gas discovery off Venezuela
http://www.offshore-mag.com/index/article-display/7574517301/articles/of...
That's lucky as Venezuela needs to find gas in the Maracaibo region right about now.
According to the 2009 South America snapshot from pipelinesinternational.com, The Trans-Caribbean Gas Pipeline currently transports gas from Colombia to Venezuela for reinjection into the oil fields in the Maracaibo basin. The Colombian fields currently supplying this gas are due to run dry by 2012 at which point the flow is supposed to be reversed with northeast Colombia receiving Venezuelan gas. Longer term regional plans include building additional pipelines so that Venezuela can ultimately be the main provider of gas to both Colombia and Ecuador.
Venezuela has truly huge gas reserves and lacks only the political/financial environment that encourages development to become a major provider of piped gas to its immediate neighbors and of LNG to world markets. Additional supply would also help them get their own energy house in order.
Venezuela is so interesting right now because it has such great potential on both the up and down sides.
Jon
I don't know what ENI considers super-giant. The field is large, water is shallow, it's close to a refinery and other markets. But the field was discovered a while back, and there has been no activity to develop it. As far as I know, they haven't even agreed on the commercial structure of the entity to develop the field, or the gas price.
Venezuela has large gas resources - but they're not producible if the government can't figure out how to give the terms companies need to get it the gas developed and produced.
IMO the fact that Mr. Chavez and his government folks cannot or will not figure out how to rapidly (relatively speaking) and greatly ramp up Orinoco oil and Vz NG production is a good thing for the World.
TPTB should encourage Vz's current government to stay in power for 10 more years and continue to slow-roll and putz around wrt oil/NG development.
Keep those resources under-developed for the time, perhaps in the early-to-mid 2020s, when oil and gas reservoir depletion from other sources becomes very worrisome.
Perhaps at whenever year this becomes widely apparent and worrisome then Vz can provide one of the World's last-ditch oil sources (at considerable cost to consumers and great profit to Vz if they are smart)...this moderate flow of oil might cushion us enough to ramp up our attempts to transition to what comes after the age of oil.
We can only hope that environmental damage to the Orinoco Belt lands will be minimized...at least the production will involved underground methods and not vast strip mining.
2) ~ 25% per year
http://www.eia.doe.gov/emeu/cabs/Venezuela/Oil.html
Thats the highest rate I ever seen.
There are decline rates and there are decline rates. I've seen 30+ % per year in high rate water drive reservoirs if they're left wide open.
But the figure is somewhat misleading. If one can drill, inject, workover, recomplete, and otherwise pour money into an oil field, and doing so makes a good return, then I propose we should not use the "technical" decline rate, but the decline rate we would see as the field declines no matter what we can do.
I used the 5 % rate to give you guys an idea of what's going on in Venezuela. If PDVSA were to name me Vice President of Production, and I didn't have to worry about the political bs, I could take the existing fields and reverse decline - but I would need the ability to invest or otherwise spend money, capped only by having to achieve say 10 % rate of return after taxes. The government would have to keep out of the way and stop nationalizing service companies and let PDVSA sign contracts with foreign companies to help, and the national payroll would have to be set to allow Venezuelans to make a decent wage, which they can't right now.
So let's say the existing fields will decline somewhat under current management, and this process can't be reversed by Hercules unless they do something radical about their communist type thinking.
That's funny, I was about to link to the same EIA page Pollux did, where they have this to say:
According to my compilation of AAPG Discovery Data 2007 saw no less than 15 oil and/or gas shows, compared with a whopping 1 in 2008 and 3 in 2009. Make of that what you will. AAPG should publish 2010 highlights in EXPLORER soon. The "Catalog of Recent Oil Discoveries" at peakoil.com has some entries from Hugoland as well, no doubt.
'capitalist' type thinking' leaves a lot to be desired in resource management too ! spindletop anyone ?
The reason I state my political orientation as "beyond left/right" is this:
Socialism and capitalism are both industrial isms. They both rely on cheap abundant resources to work. The only difference is that under those conditions, capitalism is the only one that actually do work. BUT THOSE DAYS ARE OVER.
Not really. Even if we accept the idea that resources are depleting, capitalism provides for much more efficient use and distribution of resources. Which means people live better no matter what. You see, I've lived in a communist society, I have traveled quite a bit in others, as well as societies transitioning from communism, and I also happen to be quite familiar with the Venezuela transition from capitalism to what they call XXIst century socialism.
It's easy to take apart communism and XXIst century socialism and show they don't work. If one looks at Venezuela today, and analyses what's happening, one can see the destructive power of marxist-castroite thinking.
People who refute the evidence, are merely dogmatic and sunk in a near religious belief. I deal with them everyday, and there's no way to make them change. It would be easier to make Osama bin Laden join a monastery.
Spindletop took place over 100 years ago. Communism is the destroyer of worlds. Trust me, I've been there, done that. And I helped bury the Soviet Union.
I'm fairly familiar with Venezuela's heavy oil belt and can offer the following comments/corrections:
The oil in place probably ranges up to or possibly beyond 1.3 US billion in place. The trap is so large the reservoir quality changes both areally and vertically, therefore it's difficult to generalize. However, it's possible to say the belt holds sufficient oil in place to produce a lot more than it does today by primary means only.
Some of the reservoir sectors are excellent quality, they are pumped using Progressive Cavity Pumps to enhance the flow, but this is fairly common in the oil industry - in other words, the use of PCPs doesn't mean the reservoir isn't being produced by primary means.
The upgrading process doesn't necessarily shrink the oil. The process being used cokes the crude (or a portion thereof), this shrinks it. But afterwards the cracked material can (and is) placed in hydrogenation units (which can be of different types, I won't get into the details here). When hydrogen is mixed with the cracked material coming out of the coker, the oil swells and stabilizes. This means it's possible to produce a light syncrude by adding a lot of hydrogen, and the end result is extra heavy in = syncrude out.
There's no CHOPs that I know of being used in Venezuela - although it's possible a couple of small pilots are in place. CHOPs isn't applicable, and it isn't needed. Thermal projects other than pilots are not used either. The comment made above is right regarding the need to beef up well designs for future thermal projects. However, these may not be needed for a long time, given the huge amount of oil in place which can be produced to recover 5 to 10 % of OOIP by primary means.
SAGD isn't the most viable thermal recovery system for the high quality reservoirs with moveable oil in the Orinoco Oil Belt - the oil moves, therefore it's hard to justify a SAGD process. Sectors with higher viscosity oil should not be developed first because it makes little economic sense. The most likely thermal method has already been designed by PDVSA but it's not disclosed to the public. It's not SAGD. My impression is PDVSA lacks the internal resources to implement thermal recovery in a large scale.
The map with all the little flags is meaningless. This map refers to blocks being studied under a master study called "Magna Reserva". The nations/companies engaged in the study have no rights to produce the oil, nor are the legal or commercial agreements in place to provide for future projects. There are other maps which show the areas with acreage already licensed, or with bid round awards but not fully licensed. In my opinion (and this is only my educated guess), the following are more mature:
1. Three existing deals with Total, Statoil, BP, and Chevron participation.
2. Chinese participation in Sinovensa.
3. Acreage awards announced after the Carabobo bid round (to Chevron and Repsol groups).
4. ENI award by direct negotiation
5. Russian consortium award by direct negotiation.
The others are, as far as i can tell, vaporware - they don't really amount to much.
Regarding environmental issues, I saw a comment about this topic by somebody who seems to have Canada in mind. The Oil Belt is produced using wells, not mining, and CHOPs isn't used. Therefore the environmental impact is fairly light. Wells are drilled from large drilling pads, there are no spills, water is re-injected, and the only issue I would be concerned about is future pipeline and upgrader integrity. Sometimes it helps to have been on the ground, and I have.
Hope this helps.
re: environmental impact---you don't consider this an issue?
Ghung:
The statement is wrong. I can't give you a detailed answer, but I can point out:
1. The process doesn't reject 20 % of the original crude as coke. In Venezuela, the feed stream is coked so as to reject 10 % of the feed. One COULD reject more, but it's not required. The rejected coke is sold to be used in power generation and other markets, so it doesn't have to be dumped in a deep trench.
2. There are other processes (other than coking) which involve distillation and then processing the tower bottoms into a hydrogenation unit. For example, VCC:
http://www.kbr.com/Technologies/Refining/Veba-Combi-Cracking/
The only issue with heavy oil production you could really bring up is CO2 emissions - but as it turns out in Venezuela it's possible to keep emissions low if the project finances a hydroelectric unit to generate electricity as part of the package. And this is feasible. Which makes primary heavy oil development in Venezuela greener than light oil development in a reservoir requiring gas re-injection.
you are going to have to explain that one.
Primary heavy oil development uses reservoir energy to move between 5 and 10 % of the oil in place. The oil is pumped with PCP's, and these are very efficient. If the electric power for the PCP's is generated using hydropower, and the oil is upgraded to say 20 degree API syncrude, the oil can be put to the market with a lower CO2 footprint than a light oil field using high pressure compression - because the compressors use a huge amount of horsepower and burn a lot of fuel.
I know because I have seen the CO2 emission statistics for real fields, and the heavy oil footprint is similar to slightly less if the light oil field is cycling at high GOR.
Do take into account I said cycling at high GOR, and I limit the way the heavy oil is produced and treated. However, "civilians" do need to get a lot smarter about the CO2 issue before they start tossing figures around - sometimes things aren't as simple as just looking at API.
Thanks for your insights, fdoleza.
The VCC, an ebullient bed process has been proposed for more than 30 years for upgrading Venezuelan residue, but for some reason has never prospered, as have similar processes developed elsewhere, including one developed by PDVSA's Technical Division, INTEVEP, where I was employed.
UOP also developed one called Aurabon, which seems similar to OPTIMA in Alberta in that it used deasphalting in the process (I was for it, but did not prevail). These either added or recycled cheap solids which acted as substrate to pick up the coke or metals and were purged from the process as a "drag stream". All of them resulted in significant higher yields than the Delayed Coking workhorse which, however, continues to be selected as the "process of choice" (better the devil you "know"??).
fdoleza is correct in that the coke produced in Venezuela is actually exported as fuel, probably as a supplementary fuel in coal burners--my bad in not making the distinction between what is actually done with this high-metals stuff and my opinion as to what SHOULD be done with it (when considering AGW).
I believe the stuff would be pretty inert 5 miles down in a trench entering a subduction zone, (maybe calcine it first). Tests should obviously be done first. If dumping were feasible, it would be better to dump a thermally vitrified pitch (a la Eureka) which would be even less reactive. Furthermore, if done, it should be at a single site, and not scattered all over the sea floor.
While I stated that coking would produce ~ 20 wt% based on crude, this corresponds to recovering 83 vol% (- 10% converted to gas) of the crude due to the fact that it's less dense. I never came across a coking process able to produce a synthetic crude from a 9 API feed able to produce even 80% liquid product BEFORE hydrotreating, based on initial crude volume, although it may be possible to stretch the yield somewhat for low-pressure, once-through operation, I suppose.
We don't feed 9 degree API to the coker. There are two options. First option is to run the diluted crude through an atmospheric distillation unit, take the diluent off the top, take a mid-cut from a lower tray, and take the bottoms and feed them to the coker. The second option is to take the bottoms from the atmospheric unit and feed them to a vacuum tower. The Orinoco crude can be tricky, I can't disclose everything I know, but I can say it's important to test the vacuum bottoms to make sure it's fit to run through a coker.
Other tricks: Take half the heavy crude and don't process it at all, then make syncrude, and dilute the heavy with syncrude, to make a synbit. I've seen dozens of cases using this option, and this was proposed by PDVSA to foreign corps looking at doing business in the oil belt.
Tossing coke into the ocean sounds kind of wasteful from an economic standpoint. I suspect it's more sensible to use a gasifier and inject the CO2 if you're feeling that green. I've been reading about the ice ages, and I'm not convinced CO2 is really as bad as they make it out to be - it may be saving us from another ice age anyway.
I assume you're joking about the GW -- we're a good distance from the ice ages. I can understand wanting warmer weather this time of year (25F outdoors, 16 inches of snow recently, everyone's growing ice dams), but if I'm warm here outside Boston in the winter (at a prudent elevation, above the melted-Greenland sea level), then people are probably unable to live in the center of the country.
Venezuela's a lot closer to the equator, they surely have a lot of sunlight available, and never a real shortage. If you had an oversupply of CO2, is there anything useful you could do with it, in combination with sunlight? (I'm not snarkily implying "grow plants", I'm legitimately curious what could be done, given a relatively regular and intense supply of sunlight.)
Sans a CO2 tax, and with adequate supplies of NG for process fuel and H2 production, it is surely more economic to invest in more crude and upgrader projects, than it would be in coke gasification.
CO2 recovery and injection for long-term storage is a scam that's now being exposed in Saskatchewan, where it is apparently found to be leaking out of the storage site after just a decade of injection (breaking news).
Unless it could somehow be used for algae production, there is NO economic use for excess CO2 produced in large amounts.
As I offered previously, in areas with intense solar radiation together with humidity, provided either naturally or using warm water, the Atmospheric Vortex Engine will likely be found to be the most economic and ecologic technology to produce electricity on a large scale.
In Venezuela, Lake Maracaibo or Lake Valencia, and possibly some warmer tributaries of the Orinoco would be ideal sources of warm water to function as feed to this device. It also might be reasonable to create an artificial "solar lake" in the "Faja" to serve as the warm water source for it.
With respect to AGW, (Paraphrasing)...it's hard to convince someone that some phenomenon is true if his salary (or future salary) depends on him NOT understanding it to be true.
It's not a big issue if it's leaking, the question is how fast?
If it takes 1000 years to leak what was injected in the last 10, it's a problem for the owner of the land above but a technical (and climactic) success.
The CO2 was not supposed to leak out at all.
Rather than argue about this, we'll just have to "wait and see" how fast it's coming out.
My prediction is that this occurrence will stop this "technology" cold in its tracks.
Back to the drawing board.
HOG,
Is this the program you are referring to:
http://ptrc.ca/siteimages/PTRC%20Reponse%20Kerr.pdf
http://ptrc.ca/index.php
They say there is no problem, is there other information about?
The CO2 I believe was being used as CO2 flooding for EOR, I gather this part of the program was proving fruitful, with increased oil flow, missing the win/win with the CO2 staying down hole.
Edit: Here is the other side of the story:
http://en.wikipedia.org/wiki/Weyburn-Midale_Carbon_Dioxide_Project
It appears the oil extraction side is working well, see graphs in
"No peak oil yet? The limits of the Hubbert model" by "drillo",
http://www.theoildrum.com/node/7241#comments_top
they just need to work out how to keep the CO2 down there. Have they checked their cement jobs lately?
could you fill us in on the 'breaking news' ?
Kein problem,
Here's a good overview:
http://greeneconomypost.com/carbon-capture-sequestration-leaking-12488.htm
it doesn't appear that 'natural' sources have been ruled out:
Thats an EOR project. CCS is not a serious part of it.
Serious CCS injects into brine reservoirs because that is where the capacity is to make a difference. CO2 based EOR sounds good, but actually results in net positive emissions to the atmosphere. CO2 EOR at best gives a modest offset to what is emitted by burning the oil that is produced. Most CO2 EOR doesn't even give that, it is extra CO2 to the atmosphere even before factoring burning the produced oil.
A few points about the Kerr article.
First, CO2 doesn't cause algae blooms, over-fertilization and animal excrement does. Second, CO2 doesn't kill animals (they emit quite large amounts of it themselves), but toxic algae can. Third, he's sitting above an oil field, and quite likely there are coal deposits under his property. It wouldn't be at all surprising for gas to leaking out of the ground naturally.
I assume you're joking about the GW -- we're a good distance from the ice ages.
Not necessarily. Some theories hold that we would be sliding into another ice age right now if it were not for the warming caused by higher CO2 levels in the air. We're overdue for one.
Actually, we're technically in an ice age right now, because the last one never ended. This is just an interglacial period - a temporary retreat of the glaciers before they advance again.
I had heard this very same thing -- that lacking any extra CO2 emissions, we might well be in for a chilly time, but also that we were now very far clear of that particular risk. I recall reading another article claiming that we need to save the CO2 for hundreds of thousands of years down the road, when some other effect is predicted to be strongly chilling, and I recall reading an article asserting that the very first warming occurred in some-thousand BC, related to the dawn of agriculture or something like that (that last one did not entirely make sense to me -- I had a hard time figuring out how there were enough people to make a difference).
But those are all one-offs, more or less. What I hear again and again, explained in various ways that all look credible to me, is that we're on a solid path to making things a good deal warmer than they are now.
And the New England gardener's joke, is that what happened to the glaciers, is they just retreated north, to get more rocks. (I live a short walk from the intersection of Agassiz and Moraine streets.)
Incorrect. In an ice age sea levels are 120 m lower, temps 5 decrees C lower and CO2 is 200 ppm while we are now at 390 ppm, 100 ppm higher than in the last warm period around 100,000 years ago. We are in a warm period now.
http://naturalscience.com/ns/articles/01-16/hansenFigure2.jpg
No, we are still in an ice age. Usually, this planet is much warmer than it is today. The existence of ice caps at both the north and south poles is highly unusual in its existence.
People use the term ice age colloquially to refer to the last period of maximum glacial advance, which was a cold period in an ice age, but scientifically speaking, the last ice age never ended because we still have glaciers. This is actually a warm period in the current ice age. If the ice age had ended the glaciers would be gone.
From Wikipedia: Ice Age
Think I've got a bone to pick with that Wiki author. Last 20,000 years were definitely an "inter=glacial", which is the warm period in each 120,000 year Milankovitch cycle.
Can't you see on the graph above the ice ages at 8 degrees cooler (there are big ice sheets on Canada and Northern Europe, for example) and the warm periods where temps were similar to today?
Look at the extent of ice sheets in an ice age and the sea level 120 m lower (Mexico much larger, Indonesia connected with Malaysia and Australia connected with PNG)
http://earth.rice.edu/mtpe/cryo/cryosphere/topics/ice_age.html
No, we are definitely NOT in an ice age.
Here is the latest study from NASA climatologist James Hansen:
http://www.columbia.edu/~jeh1/mailings/2011/20110118_MilankovicPaper.pdf
The level of knowledge on our climate history is shocking
The greater issue is not "warmer/colder" but disruption to weather patterns. Humanity has built and settled populations based on historic weather patterns.
Regional climate models are more uncertain than global ones. None-the-less, more than one model predicts a severe drought starting in the 2030s and hitting hard by 2060s. Combined with agriculture "till the end" exposing tilled & disturbed ground, a Super Dust Bowl from Kansas to California is quite possible. It is my (limited) understanding that a late summer ice free Arctic Ocean is the trigger, although a look at Lake Mead suggests that we have a running start.
Add all the port cities being impacted, plus dust from the Super Dust Bowl in the Mississippi River Valley, and the comfortably habitable areas of the Lower 48 may be limited to the Pacific Northwest and the inland East Coast. 400+ million Americans (assuming no die-off) will be packed in Chinese densities there. But the winters will be milder :-/
Not a certainty, but a very distinct possibility. A risk that we can still either minimize or maximize, speed up or delay. And only one of a number of Climate Change risks.
Best Hopes for Making a Bad Situation a Bit Better,
During the last 500,000 years, under natural climate change (Milankowitch cycles plus CO2 feed-back), we had following CO2 concentrations:
in warm periods: around 300 ppm
in ace ages: around 200 ppm
(sea level difference 120 m, temp difference 5 degrees C)
We are now at 390 ppm. We'll never have another ice age in the foreseeable future, there is just too much CO2 already in the atmosphere and the next phase of the Milankowitch cycle towards cooling would be too weak to overcome that.
For every ton of CO2 emitted now, there is still 30% of that CO2 in the atmosphere after 100 years. It's called the CO2 impulse response function:
http://unfccc.int/resource/brazil/tuning_carbon/bern_irf.pdf
The only place which could cool down is Europe if the Gulf stream stops bringing warm water to the North East Atlantic. But it could be that global warming from CO2 may override that local cooling. All we can safely say is that we are doing a gigantic experiment with the world climate by undoing the geo-sequestration of CO2 into fossil fuels during millions of years which cooled down planet Earth into a livable place for humans. We are not dinosaurs munching fern trees at the polar circle.
The incredible journey of oil
http://www.abc.net.au/science/crude/
I believe this is what the Wabash River repowering project was using for a while (and may still be using).
From Venezuela to Indiana, and still cheaper than Illinois coal. That's quite the economics lesson, no?
While it may seem "economic" on the surface to add petcoke to coal burners, I'm not sure that the neighbors of such facilities know all that they "should" know about what happens to the air-water-soil around them when petroleum coke high in metals is added into the mix, in terms of what is coming out of the plant as slag, fly-ash, or "acid rain".
Just sayin'
I thought we were doing a much better job now of capturing that stuff and keeping it out of the air (instead depositing it in piles, where it gets rained on and leaches and/or flows downhill).
And don't we eventually concentrate all the heavy metals to a point where they become economical to refine?
That's precisely what TPTB would "like" you to believe. Seems their MSM "gatekeeping" strategy is working to perfection.
The adding of petcoke to coal fuel streams is doing just the opposite of concentrating the metals for recovery--their mantra seems to be "dilution is the solution to pollution".
In the case of Wabash River, the pulverized coke is gasified with 95% oxygen and the slag quenched to solid. Particulates are filtered and returned to the gasifier. That's one coal-burner which shouldn't worry us on that account.
Who knows what the future will bring, but the combined net oil exports (BP data set) from Canada and Venezuela have not been very encouraging in recent years:
What is the quality of the Venezuelan reservoirs like after they have been depleted of their primary production? Is it actually feasible to use any other methods on them, or is the primary amount all that ever gets produced because they are too badly wormholed for any other process to work afterwards?
I don't think the Faja reservoirs producing under primary production are wormholed. The standard well design provides for a slotted liner in a horizontal well, and the slots are cut to avoid sand production. Start up sequence is such that sand is kept out - it's very expensive to clean up sand in a 1500 meter horizontal hole if the well sands up.
Wormholes are seen in vertical wells when they are completed to produced as CHOPs wells - sand is produced on purpose and it's seen at the surface in large amounts. This is not the case in Venezuela.
It's also important not to lump all Venezuelan reservoirs in one group. There are lots and lots of them, just like in Canada, but even more so because Venezuela has two major and quite distinct oil provinces, Eastern Venezuela and the Lake Maracaibo basin - I'm not listing the others to keep this simple.
I believe the dicussion here is mostly about the Orinoco Oil Belt. The belt isn't depleted yet - the oldest reservoir is still fairly young. Therefore it's hard to tell what shape they'll be in when they're depleted. Indeed there should be serious concerns regarding the ability to use secondary recovery in SOME of the Orinoco reservoir sectors after primary depletion.
fdoleza,
With your experience in Venezuela you will know that PDVSA experimented with a SAGD pilot in Tia Juana at Lake Maracaibo in the 90's. We drilled a horizontal pair but I don't know if the steam equipment was ever installed.
I also participated in a presentation given to INTEVEP in Los Teques about horizontal drilling and SAGD production.
- borarah
borarah, I was chatting a few minutes ago with a lady engineer who did a thesis on the Tia Juana pilot wells. Tia Juana isn't a good place for SAGD, that basin subsides like crazy.
I have all the literature and I have seen a lot of confidential material I can't discuss here. As far as I can see, anybody talking SAGD for Venezuela is out of phase with reality. But then, I remember a few years ago I had a boss who told me "there's no need to think too hard about it, we'll do SAGD like they do in Canada". Which proves you can be very experienced in this business, yet innocent enough to think you can copy something from elsewhere and it'll work just fine.
Thanks for expanding so clearly on the Venezuela situation.
I'm guessing you are extremely busy and have limited time for reading outside your field but you just might find this QuaternaryScienceReviews paper History of Sea Ice in the Arctic worth your time. Its about as balanced and thorough as you can get in twenty-two pages.