OGPSS - Venezuela after Hugo Chavez

With the death of the Venezuelan President Hugo Chavez the future production, and exports of Venezuelan crude are gaining a little new attention. I had noted in the last post that there is a difference of around 400 kbd between the 2.379 mbd that outside observers report to OPEC that the country is producing, and the 2.768 mbd that Venezuela itself reported. The question now becomes one as to whether the new President will be able to resurrect an industry that has overseen a slow decline in overall production, with a more rapid decline in exports.


Figure 1. Venezuelan oil statistics (Energy Export Databrowser)

My short answer to that question is No! It is based on a number of reasons, and may be swamped by the voices that note that the country has a vast remaining pool of oil in the Orinoco Basin, that the USGS has estimated to be more than a trillion barrels in size, of which some 513 billion barrels are technically recoverable. But there have been a number of posts about those numbers and the more critical number which is that of the rate of oil production.

Colin Campbell reminded us in his 2006 Review of the country that the Venezuelan Government was one of those urging the creation of OPEC, back in 1960. Back when that piece was written Colin expected that production, which had been falling as the reserves in the Lake Maracaibo region declined, would start to wind back up, as the heavy and extra heavy oils of the Orinoco were brought into a higher level of production. And he anticipated that, by now, the country would be producing around 3 mbd, which it is not.

One of the requirements before one can market the heavy oil is to have refineries that can process the oil. The United States, which imports around 1 mbd of Venezuelan crude, has the Citgo refineries, which are wholly owned by PDVSA (the Venezuelan oil company). Whether that will influence their switch to Canadian crude if the Keystone pipeline is put in place is an open question. But easing the American demand might help with Venezuelan relations with China.


Figure 2. US Monthly imports of crude and Petroleum Products from Venezuela (EIA )

China, which has refineries that Sinopec built that can also handle the crude, has stepped in here and spent over $40 billion with much of this in loans to be repaid through increased oil exports. Back in 2007 China had made the decision to pull out of Canada, and to concentrate its investments in Venezuela instead. Since that time they loaned Venezuela over $20 billion, in return for a commitment for oil exports that were to reach 1 mbd in 2012. The date to reach that target has now slipped to 2015 as overallproduction has continued to decline.

Last August President Chavez announced a $130 billion plan for investment in the Orinoco.

He said that there are 150 different clusters of oil wells in the Belt, but the goal in the next six years is to increase that number to 500. Before the nationalization of the Belt, there were just 37 clusters.

The clusters are comprised of 24 separate oil wells, each of which extract around 1,200 barrels per day. At these facilities, hydrocarbons are extracted using 45-meter drills purchased in Venezuela and assembled in Venezuela.

“All this has been nationalized, which before was the property of multinationals, and production has also been increased,” the president said. He recalled that before the government took control of the Belt, there were just 2,800 wells, while now there are more than 4,000.

Because the Orinoco crude is very heavy, to an API gravity of 9 degrees, it is difficult to produce and requires a considerable energy investment to extract and process the crude.

Last September two joint ventures came on stream. That at Petromiranda, where PDVSA has Russian partners began producing 1,500 bd, after an investment of $800 million, with a goal of eventually reaching 45,000 bd. At the same time Petromacareo, where PDVSA is partnering with the Vietnamese, came on line at 800 bd, with an initial target production of 4,000 bd. (The project has slipped from a target start date of early 2011, and the ultimate goal of 200 kbd from Petrimacareo is in more doubt.)

The crude has to be upgraded, and TNK-BP is partnering to double the capacity of the Petromangas upgrader from 120 to 250 kbd. Until that capacity is increased Orinoco production may be limited.

There is thus a history of project slippage and missed targets that is unlikely to improve in the short term. New plans for further investment either by the Chinese, Indians or Russia are now on hold, while the Presidential election to replace President Chavez is decided, but the experience in the last couple of years is likely indicative that progress in increasing production will be difficult to achieve and when set against a rising domestic consumption (as the Export Land Model predicted) is already leading to a fall in exports.

One of the drivers for that increase in domestic consumption is that the price of gasoline in Venezuela is $0.04 per gallon (four cents). In contrast, in Saudi Arabia it is around $0.61. The low price of gas means that there has been a significant increase in demand, exceeding that domestically available. As a result the country has been importing gas at up to $100 a barrel to sell it for $5 – you can’t balance those books by increasing the volume of sales!!

Yet cutting back on domestic consumption, or increasing prices could prove difficult for the incoming President. So maybe it would be a good idea to invest in the Keystone pipeline, as a simple precaution??

OGPSS - Production from Venezuela and new customers for them

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.

The steady fall in Venezuelan imports to the USA (EIA )
Please note there is an additional comment appended on the loss in volume on going through the ugraders.

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:

Different regions of the Orinoco Belt (Energy-pedia news )

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 over at TOD has commented on this loss.

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 viscocity 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.

Artist's illustration of the SAGD process (Devon Canada Corp)

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 viscocity, hotter fluid.

Kerosine 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)

(Source HeavyOilInfo.com)

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.



The swop deal that I mentioned last week involving Venezuela, Belarus and Azerbaijan is proving to be a little more complex than the original simple swop 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 swopping 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.

OGPSS - Venezuela, heavy crudes, API gravity and refinery gains

Because the world market is increasingly having to accommodate crudes that are heavier and less easy to refine into desirable, profitable products I thought I would revisit my discussion from earlier in the series about the limitation on global oil production, due to the need for suitable refineries to process the oil that is produced, before it can reach and be used by the ultimate customer.

I have covered the operations of refineries in the past, but this time I thought I would dwell a little more on some of the factors that relate to the type of oil that is being refined. It is perhaps timely to do so, given that China is moving forward with plans to construct a refinery that will process the heavy Venezuelan crude that, until now, has largely been sent to specialized refineries in the United States that are designed to handle it. In 2008 Venezuela exported 120 kbd of oil to China (out of a total of 1.89 mbd, of which the USA imported 1.19 mbd). This past year the flow to China is reported to have increased to 362 kbd. It might be noted that the recent diplomatic leaks known as the Wikileaks saga has revealed cables that suggest that China was getting some of this oil for $5 a barrel, and then selling it for more on the open market, including possibly to the USA. This could be quite possible since it is also reported that while Venezuela said it exported 460 kbd to China, Chinese figures put the volume this year at 132 kbd.

The largest supply of oil remaining in Venezuela is that in the Orinoco Belt, which the USGS has estimated holds a reserve of some 513 billion barrels. (Which, for reference is about twice the size of the Saudi Arabian reported reserve.) The problem with the oil is that it has an API of 9 degrees. Which is where I need to digress a little and explain to those not familiar with the term, what API gravity is, and the significance of a value below 10 degrees.

In the following explanation I am going to use a couple of examples taken from “Petroleum Refining in Non-Technical Language” by William Leffler, which has some clear descriptions that I cannot hope to improve on, in explaining some of these issues.

As I had mentioned in the earlier post, the crude that comes from the ground is a mixture of compounds of carbon and hydrogen with the compounds individually having roughly twice as many hydrogen atoms as carbon, and with the higher numbered compounds being heavier. As a way of characterizing the crude at this point, the American Petroleum Institute developed a measure known as the API gravity. The API gravity, which is expressed in degrees, is obtained from the equation:


If you recognize that the specific gravity of a fluid is the relative density of the fluid when compared with water (at 60 deg F in this case), then you will see that with an S.G. of 1, water has an API gravity of 10 degrees. Fluids, such as the Orinoco crude, with an API gravity of 9 degrees, are thus denser than water, and the scale is inversely related to density, so that the higher density fluids such as asphalt, have a lower API gravity (in this case 11 degrees) than lighter fluids such as light crude (36 degrees) and gasoline (60 degrees).

The initial separation of the different compounds in the crude is achieved by heating the crude to about 750 degrees F, and feeding the result into a distillation column, where the volatized fractions of the mix can be condensed back out and separated out on trays at different temperature levels. The hydrocarbon content can thus be characterized by the relative levels of fluid that condense out at different temperatures, and the product is known as a Distillation Curve for that crude. For example these are the basic curves for some of the heavy crudes from South America.

(Original Source OGJ Nov 18, 2002) I have added the temperature ranges in which the different fractions of the crude would settle out.

You can see that, there is not, initially, a lot of the lighter fractions available in these crudes., which are also because of this, more viscous and difficult to move around the plant.

To produce those higher fractions the refinery will first remove the lighter fractions, as described above, but then will further heat the remaining crude to the point that the heavier hydrocarbons break down into smaller molecules. Consider the case of the C16H34 Cetane molecule, which will break down into a combination of C8H18 octane molecules; C6H12 hexene molecules and C2H4 (ethylene) molecules roughly in the ratio of 50:38:12. When this happens the volume of the product will also increase. (I am taking this example, and the numbers from Leffler’s text).

The density of the original fluid was 7.2 lb/gal, it now breaks down into the smaller molecule hydrocarbons.

If we consider the original volume weighed 7.2 lb (1 gal) then 50% of that would become C8H18, which would weigh 3.6 lb. However octane is a lighter hydrocarbon that only weighs 5.9 lb/gallon, so that the resulting volume would occupy (3.6/5.9) 0.61 gallons.

In the same way the 38% of the original 7.2 lb would break down into the same weight of C6H12, some 2.7 lb, but hexene has a density of 5.6 lb/gallon. The resulting volume would thus occupy (2.7/5.6) 0.48 gallons.

And the third fraction would be the 12% that turns to ethylene, some 0.9 lb that would, at the new density (3.1 lb/gallon) occupy 0.29 gallons.

If one adds up the three “cracked” volumes the total is now 1.38 gallons, rather than the original 1 gallon, and this is how “refinery gains” are developed (illustratively) within the refinery. To keep the temperatures down during the cracking process it is generally carried out at a lower pressure than atmospheric, since this allows the fluid to boil at a lower temperature.

The heavier the crude then the more complex, and expensive the process of refining becomes. Often even to produce the original crude to the point that it can be pumped long distances, it must first be upgraded to a synthetic crude in an upgrader, located on site. It is this process that the Canadians have found a way to work around, though this is not yet the case with Veneuela. As a result as the different blocks of the Orinoco Basin are being developed, they only come into full production when upgraders have been constructed to handle the flow.

Given the need for considerable processing of the Venezuelan crude, which can also contain other contaminants such as vanadium., it is important to note that about the same time as the USGS was upgrading its figures for the Venezuelan reserve, that country and China were approving a $6-billion joint venture to build a 400 kbd refinery in China to handle that crude. Whether the crude is processed into a syncrude before shipping to China is not clear, but this is all part of the effort by Venezuela to increase exports. (The crude will come from Junin Block 4.)

Veneuela has contracted with a number of other country partners for production from other parts of the Orinoco Basin. Petrovietnam will help develop Junin Block 2, which is slated to have a production capacity of 200 kbd by the end of this year; Italy’s ENI has a target of 240 kbd starting to come on line in 2013 from Junin Block 5, though the refinery to process this into diesel for Europe won’t be built until 2016; Russia will partner in Junin Block 6 to develop 450 kbd at some unspecified date. In addition a combination of partners are to develop blocks in the Carabobo region, with a total production of 800 lbd, with the production to be on stream by 2013, though upgraders for the crude won’t be ready until 2017. The Chinese involvement has now been approved, with a performance period of 25 years, and further the Chinese have agreed to develop Junin 1 and Junin 8 at 200 kbd each, for a grand total of 800 kbd, which will require a $40 billion investment. Should all the investments that Venezuela envisages come to pass, then they anticipate that the country could be producing 7 mbd by 2021.

It is worth noting that the Junin 1 block was supposed initially to be developed by Belarus, but that fell through. However, in a four-party deal, Venezuela has agreed that it would send some of its crude to the USA, if Azerbaijan agreed to send an equivalent amount of its oil to Belarus. Azerbaijan is increasing production and has just reached the 1 mbd mark.

Whether Venezuela will reach the levels of production anticipated, or at the rate anticipated, is still, of course some matter of debate, but it does explain where some of the more Cornucopian projections acquire some of their statistics.

P17. Pick Points

Half-a-dozen or so stories of interest:

Well that’s a turn up for the book, Cesar Chavez is looking for help in the Venezuelan oilfields. With declining production and low prices, new technical help is needed to reverse the trend that has led to a fall of around 100,000 bd/year down from 3.4 mbd to 2.3 mbd. This is about the amount, actually 90,000 bd, that Venezuela ships to Cuba. There is hope that new projects in the Orinoco Belt might yield 1.2 mbd. Certainly the industry could use the work with the rig count falling so that there are 1,589 still out there, of whom 1,239 are drilling for natural gas. Horizontal drilling comprises 552 rigs, and directional drilling 315. Maybe they can start drilling for water in Southern California, as the threat of water rationing down there has been raised.

While conventional oil production in the US dropped below 5 mbd in December, the need to find alternates sooner than that from biofuels will be available is leading Total to take a 50% share of a project that involves in-situ combustion, just as new leases become available in Colorado. However the incoming Secretary of the Interior is against the idea. Incidentally there are still some 334 offshore platforms that are still shut down as a result of Hurricanes Gustav and Ike.

Patience is now definitely wearing thin as the Russian;Ukrainian dispute continues. It is not clear if the monitors have much to do other than “sit in hotel rooms and drink horilka.” (Ukrainian vodka). In Serbia they now run the risk of overloading the electricity circuits, as the lack of natural gas is causing a switch to electric heaters, although, over the weekend Serbia had enough that it shipped some over to Bosnia, to help out there where over 100,000 households have no heat and the temperature is down to – 29oC. The latest Russian move is to suggest a Gas Summit in Moscow this weekend, however since Ukraine still doesn’t have a contract to purchase gas for itself for this year, it is unlikely that much progress will be made. Well at least Prime Minister Putin can paint while he waits. The visits of the Slovak and Bulgarian Prime Ministers to Moscow had no effect, and questions as to who gets paid what for the gas are circulating.

Given that UK Coal is planning on putting wind turbines on old coal mine sites and that plans are moving ahead to open 58 new or enlarged surface mines, half of which have already been approved, despite the furor over building new coal-fired plants. Northumberland seems to be the main place they plan the mines. (And for those that wonder I have seen one site turned into a golf course so you would never know the mine had been there), and there are 6 new coal-fired power stations being planned. Current underground mines are producing at up to 3 million tons/year, however the recent decline in demand for power has led some countries to cut back.

You would have thought that with the gas crisis, coal mining in Bulgaria would be seeing good times, but the Bobov Dol mine, in Bulgaria unable to sell coal to power plants is being closed this month. The story is a little more complex that it first appears, however, since it turns out that the local power plant was privatized, and the new owner had other mines that he owns and wants to get the coal from.

There are more stories over at The Energy Bulletin, or on Drumbeat at The Oil Drum.